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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997. Commission File No. 1-3429
Maine Public Service Company
(Exact name of registrant as specified in its charter)
Maine 01-0113635
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
209 State Street, Presque Isle, Maine 04769
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 207-768-5811
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Common Stock, $7.00 par value American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Title of Class
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X . No .
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates at March
26, 1998: $22,540,422.
The number of shares outstanding of each of the issuer's classes of common
stock as of March 26, 1998.
Common Stock, $7.00 par value - 1,617,250 shares
DOCUMENTS INCORPORATED BY REFERENCE
1. The Company's 1997 Annual Report to Stockholders is incorporated by
reference into Parts I, II and IV.
2. The Company's definitive proxy statement, to be filed pursuant to
Regulation 14A no later than 120 days after December 31, 1997, which is the end
of the fiscal year covered by this report, is incorporated by reference into
Part III.
(Page 1 of 44 pages)
PART I Form 10-K
Item 1. Business
General
The Company was originally incorporated as the Gould Electric
Company in April, 1917 by a special act of the Maine legislature. Its
name was changed to Maine Public Service Company in August, 1929. Until
1947, when its capital stock was sold to the public, it was a subsidiary
of Consolidated Electric & Gas Company. Maine and New Brunswick
Electrical Power Company, Limited, the Company's wholly-owned Canadian
subsidiary (the "Subsidiary") was incorporated in 1903 under the laws of
the Province of New Brunswick, Canada. The properties of the Company
and Subsidiary are operated as a single integrated system.
The Company engages in the production, transmission and
distribution of electric energy to retail and wholesale customers in all
of Aroostook County and a small portion of Penobscot County in northern
Maine. Geographically, the service territory is approximately 120 miles
long and 30 miles wide, with a population of approximately 82,000.
The service area of the Company includes one of the most important
potato growing and processing sections in the United States. In
addition, the area produces wood products, principally pulp wood for
paper manufacturing.
The Subsidiary is primarily a hydro-electric generating company.
It owns and operates the Tinker hydro plant in New Brunswick, Canada,
and sells to the Company the energy not needed to supply its wholesale
New Brunswick customer. During 1997, sales to the Company amounted to
77,323 MWH out of the 102,681 MWH generated for sale at Tinker.
As discussed further in Items 3(a) and (b) of the "Legal
Proceedings" section of this Form 10-K, the Company is proceeding with
the sale of generating assets in accordance with Maine's new electric
utility deregulation law.
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Form 10-K
PART I
Item 1. Business - Continued
The Company and the Subsidiary's net energy production, including
generated and purchased power, required to serve all customers, was
630,457 MWH for the twelve months ended December 31, 1997. The
following table sets forth the sources from which the Company and the
Subsidiary obtained their power requirements in 1997.
1997 Megawatt-hours Generated
Sources of Power or Purchased
Net Generation:
Hydro 107,734
Steam 26,758
Diesel (429)
Total 134,063
Purchases:
Nuclear Generated 0
Fossil Fuel Generated 371,689
Biomass Generated 125,199
Total 496,888
Inadvertent Received (494)
Total System 630,457
As of June 4, 1984, the Company entered into a Power Purchase
Agreement (PPA) with Sherman Power Company, which assigned its interest
in the Agreement to Wheelabrator-Sherman Energy Company (W-S), formerly
Signal-Sherman Energy Company, (a cogenerator), for 17.6 MW of capacity
which began July, 1986. The current contract expires in 2001. As
explained in Item 3(e) of the "Legal Proceedings" section of this Form
10-K, the Company and W-S have agreed to a restructuring of the PPA.
The amended agreement, approved by the MPUC, should help relieve
financial pressure caused by the recent closure of Maine Yankee and help
avoid substantial increases in the Company's retail rates. The Board of
Directors of the Finance Authority of Maine (FAME) has authorized the
issuance and sale of securities which will be used for an up-front
payment to W-S. The Company expects that the financing will be
completed during the second quarter of 1998.
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Form 10-K
PART I
Item 1. Business - Continued
Financial Information about Foreign and Domestic Operations
Financial Information Relating
To Foreign and Domestic Operations
(In Thousands of U.S. Dollars)
1997 1996 1995
Revenues from
Unaffiliated Customers:
Company-United States 54,291 56,521 54,585
Subsidiary-Canada 781 743 694
Intercompany Revenues:
Company-United States 728 683 719
Subsidiary-Canada 1,672 2,424 1,877
Operating Income:
Company-United States 567 4,585 3,997
Subsidiary-Canada 344 703 367
Income (Loss) before Extraordinary Items
Company-United States (2,521) 1,366 503
Subsidiary-Canada 344 745 418
Extraordinary Items, Net of Tax
Company-United States - - (6,236)
Net Income (Loss)
Company-United States (2,521) 1,366 (5,733)
Subsidiary-Canada 344 745 418
Identifiable Assets:
Company-United States 156,207 109,891 107,138
Subsidiary-Canada 7,274 6,823 6,936
The identifiable assets, by company, are those assets used in each
company's operations, excluding intercompany receivables and
investments.
-4-
Form 10-K
PART I
Item 1. Business - Continued
Source of Revenues
In 1997, consolidated operating revenues totaled $55,072,196.
The percentages of revenues derived from customer classes are as
follows:
%
Residential 37.0
Small Commercial and Industrial 31.6
Large Commercial and Industrial 17.2
Public Authorities 1.2
Sales to Wholesale Customers for Resale 3.9
Other Sales and Other Revenues 9.1
Total 100.0
Sales to wholesale customers for resale includes two wholesale
customers that entered into various contracts with the Company in 1996.
These contracts contained rates lower than those typically allowed under
FERC's traditional ratemaking. Capitalizing on the availability of low
cost power in New England, the wholesale customers issued a request for
proposal in September, 1994 for their purchased power requirements
effective January 1, 1996. Houlton Water Company (Houlton), selected an
offer from another utility, and began taking service from that utility
starting January 1, 1996. In 1995, sales to Houlton, under an earlier
contract, represented 11.1% of the Company's consolidated MWH sales and
8.4% of consolidated operating revenues, making Houlton the Company's
largest customer for 1995. The remaining wholesale customers, Van Buren
Light and Power District (Van Buren) and Eastern Maine Electric
Cooperative, Inc. (EMEC) selected the Company's six-year proposal, which
cannot be terminated before December 31, 1998. The new rates for these
two customers were effective January 1, 1995. Van Buren and EMEC
represented 4.5% of consolidated MWH sales and 2.5% of consolidated
operating revenues for the year ended December 31, 1997.
During 1996 and 1997, the Company entered into long-term power
contracts with five of its largest customers. In exchange for discounts
from the Company's standard rates, these customers agreed to purchase
all of their electrical requirements from the Company through the year
2000. All five of these customers produced evidence of hardship to
continue operations in the area or were investigating self generation,
criteria that the Maine Public Utilities Commission (MPUC) reviewed
before approving these load-retention contracts.
On November 13, 1995, the Maine Public Utilities Commission
approved a Stipulation signed by Maine Public Service Company, the
-5-
Form 10-K
PART I
Item 1. Business - Continued
Commission Staff and the Maine Public Advocate. This Stipulation, which
became effective January 1, 1996, established a multi-year rate plan for
the Company that will provide our customers with predictable rates
through 1999 and shares operating risks and benefits between the
Company's shareholders and customers. For more information on the rate
plan, see Item 3(g) of the "Legal Proceedings" section of this Form 10-
K.
For additional discussion on revenues, see the 1997 Annual Report
to Stockholders, pages 4 and 5, "Analysis of Financial Condition and
Review of Operations-Operating Revenues and Energy Sales" and pages 9 to
11, "Regulatory Proceedings", which information is incorporated herein
by reference.
Regulation and Rates
The Company is subject to the regulatory authority of the Maine
Public Utilities Commission (MPUC) as to retail rates, accounting,
service standards, territory served, the issuance of securities and
various other matters. With respect to wholesale rates and certain
other matters, the Company is or may be subject to the jurisdiction of
the Federal Energy Regulatory Commission (FERC). The Company maintains
its accounts in accordance with the accounting requirements of the FERC
which generally conform with the accounting requirements of the MPUC.
At this time, the Company is not subject to the Public Utilities
Regulatory Policies Act of 1978 ("PURPA") because it has not exceeded
the threshold of 2,000,000,000 kilowatt-hours excluding wholesale sales.
However, the Maine Legislature has by statute instructed the MPUC that
it may consider PURPA standards in rate proceedings before that
Commission.
The generating facilities of the Company and Subsidiary meet the
applicable current environmental regulations of State and Federal
governments of the United States and Provincial and Dominion governments
of Canada, except for the three diesel stations (12 MW) and the oil-
fired generating plant located in Caribou, Maine (23 MW). As discussed
in Item 2. "Properties" below, the oil-fired Steam Units 1 and 2 at the
Caribou facility have been placed on an inactive status. The Maine
Department of Environmental Protection (DEP), in response to the
Company's application for air emission licenses, has indicated that the
application did not demonstrate that Ambient Air Quality Standards and
Increments will not be violated. With the cooperation of the DEP Staff,
the Company is studying what steps, if any, are required for licensing,
and cannot determine at this time what, if any, additional capital
expenditures may be required. As discussed in Items 3(a) and (b) of the
"Legal Proceedings" section of this Form 10-K, the Company is proceeding
-6-
Form 10-K
PART I
Item 1. Business - Continued
with the sale of generating assets in accordance with Maine's new
electric deregulation law.
See the 1997 Annual Report to Stockholders, pages 9 to 11,
"Analysis of Financial Condition and Review of Operations - Regulatory
Proceedings", which information is incorporated herein by reference, for
additional information on regulatory matters.
Franchises and Competition
Except for consumers served at retail by the Company's wholesale
customers, the Company has practically an exclusive franchise to provide
electric energy in the Company's service area. For additional
information on changes to the future structure of the electric utility
industry in Maine, see Item 3(a) of the "Legal Proceedings" section of
this Form 10-K.
Employees
The information with respect to employees is presented in the 1997
Annual Report to Stockholders, page 9, "Employees", which information is
incorporated herein by reference.
Subsidiaries and Affiliated Companies
The Company owns 100% of the Common Stock of Maine and New
Brunswick Electrical Power Company, Limited (the Subsidiary). The
Subsidiary owns and operates the Tinker Station located in the Province
of New Brunswick, Canada. The Tinker Station has five hydro units with
total capacity of 33,500 kilowatts and a small diesel unit of 1,000
kilowatts. The Subsidiary serves the community of Perth-Andover in New
Brunswick, with the remaining energy exported to the Parent Company in
Maine under license of the National Energy Board of Canada. On June 16,
1988, the export license was renewed to 2008.
The Company owns 5% of the Common Stock of Maine Yankee, which
operated an 860 MW nuclear power plant (the "Plant") in Wiscasset,
Maine. On August 6, 1997, the Board of Directors of Maine Yankee voted
to permanently cease power operations and to begin decommissioning the
Plant. The Plant experienced a number of operational and regulatory
problems and has been shut down since December 6, 1996. The decision to
close the Plant permanently was based on an economic analysis of the
costs, risks and uncertainties associated with operating the Plant
compared to those associated with closing and decommissioning it. The
Plant's operating license from the Nuclear Regulatory Commission (NRC)
was due to expire on October 21, 2008.
-7-
Form 10-K
PART I
Item 1. Business - Continued
The Plant generally provided reliable and low-cost power from the
time it commenced operations in late 1972 to 1995. Beginning in early
1995, however, Maine Yankee encountered various operational and
regulatory difficulties with the Plant. In 1995, the Plant was shut down
for almost the entire year to repair a large number of steam generator
tubes that were exhibiting defects. Shortly before the Plant was to go
back on-line in December 1995, a group with a history of opposing
nuclear power released an undated, unsigned, anonymous letter alleging
that in 1988 Yankee Atomic (then an affiliated consultant of Maine
Yankee) and Maine Yankee had used the results of a faulty computer code
as a basis to apply to the NRC for an increase in the Plant's power
output. In response to the allegation, on January 3, 1996, the NRC
issued a Confirmatory Order that restricted the Plant to 90 percent of
its licensed thermal operation level, which restriction was still in
effect when the Plant was permanently shut down.
As a result of the controversy associated with the allegations, the
NRC, at the request of the Governor of Maine, conducted an intensive
Independent Safety Assessment (ISA) of the Plant in the Summer and Fall
of 1996. On October 7, 1996, the NRC issued its ISA report, which found
that while the Plant had been operated safely, there were weaknesses
that needed to be addressed, which would require substantial additional
spending by Maine Yankee. On December 10, 1996, Maine Yankee responded
to the ISA report, acknowledged many of the weaknesses, and committed to
revising its operations and procedures to address the NRC's criticisms.
Another result of the controversy associated with the allegations
was an investigation of Maine Yankee initiated by the NRC's Office of
Investigations (OI), which, in turn, referred certain issues to the
United States Department of Justice (DOJ) for possible criminal
prosecution. Subsequently, on September 27, 1997, the DOJ, through the
United States Attorney for Maine, announced that its review had revealed
no grounds for criminal prosecution. The Company believes that the OI
investigation, however, could ultimately result in the imposition of
civil penalties, including fines, on Maine Yankee.
In 1996, the Plant was generally in operation at the 90-percent
level from late January to early December, except for a two-month outage
from mid-July to mid-September. The Plant was shut down again on
December 6, 1996, to address several concerns, and has not operated
since then. The precipitating event causing the shutdown was the need to
evaluate and resolve cable-separation compliance issues, and on December
18, 1996, the NRC issued a Confirmatory Action Letter requiring the
Plant to remain shut down until Maine Yankee's plan for resolving the
cable-separation issues was accepted by the NRC. Subsequently, Maine
Yankee uncovered additional issues, including among others the
-8-
Form 10-K
PART I
Item 1. Business - Continued
possibility of having to replace defective fuel assemblies, address
additional cable-separation issues, and determine the condition of the
Plant's steam generators, all of which contributed to further
operational uncertainty. On January 29, 1997, the Plant was placed on
the NRC's Watch List, and on January 30, 1997, the NRC issued a
supplemental Confirmatory Action Letter requiring the resolution of
additional concerns before the Plant could be restarted.
In December 1996, Maine Yankee requested proposals from several
utilities with large and successful nuclear programs to provide a
management team, and ultimately contracted with Entergy Nuclear, Inc.,
effective February 13, 1997, for management services that included
providing a new president and regulatory compliance officer. The
Entergy-provided management team made progress in addressing technical
issues, but a number of operational and regulatory uncertainties
remained. On May 27, 1997, the Board of Directors of Maine Yankee voted
to minimize spending while preserving the options of restarting the
Plant or conveying ownership interests to a third party. After
unsuccessful negotiations with one prospective purchaser, Maine Yankee
found no other interest in purchasing the Plant and, based on its
economic analysis, closed the Plant permanently.
As required by the NRC, on August 7, 1997, Maine Yankee certified
to the NRC that Maine Yankee had permanently ceased operations and that
all fuel assemblies had been permanently removed from the Plant's
reactor vessel. On August 27, 1997, Maine Yankee filed the required
Post-Shutdown Activities Report with the NRC, describing its planned
post-shutdown activities and a proposed schedule.
The Company's 5% ownership interest in Maine Yankee's common equity
amounted to $4.0 million as of December 31, 1997, and under Maine
Yankee's Power Contracts and Additional Power Contracts, the Company is
responsible for 5% of the costs of decommissioning the Plant. Maine
Yankee's most recent estimate of the cost of decommissioning is $380.4
million, based on a 1997 study by an independent engineering consultant,
plus estimated costs of interim spent-fuel storage of $127.6 million,
for an estimated total cost of $508 million (in 1997 dollars). The
previous estimate for decommissioning, by the same consultant, was
$316.6 million (in 1993 dollars).
On September 1, 1997, Maine Yankee estimated the sum of the future
payments for the closing, decommissioning and recovery of the remaining
investment in Maine Yankee to be approximately $930 million, of which
the Company's 5% share would be approximately $46.5 million. Legislation
enacted in Maine in 1997 calling for restructuring the electric utility
industry provides for recovery of decommissioning costs, to the extent
-9-
Form 10-K
PART I
Item 1. Business - Continued
allowed by federal regulation, through the rates charged by the
transmission and distribution companies. Based on the Maine legislation
and regulatory precedent established by the FERC in its opinion relating
to the decommissioning of the Yankee Atomic nuclear plant, the Company
believes that it is entitled to recover substantially all of its share
of such costs from its customers and, as of December 31, 1997, is
carrying on its consolidated balance sheet a regulatory asset and a
corresponding liability in the amount of $43.4 million, which is the
$46.5 million discussed above net of the Company's post-September 1,
1997 cost-of-service payments to Maine Yankee.
On September 2, 1997, the MPUC released the report of a consultant
it had retained to perform a management audit of Maine Yankee for the
period January 1, 1994, to June 30, 1997. The report contained both
positive and negative conclusions, the latter including: that Maine
Yankee's decision in December 1996 to proceed with the steps necessary
to restart the Plant was "imprudent", that Maine Yankee's May 27, 1997
decision to reduce restart expenses while exploring a possible sale of
the Plant was "inappropriate", based on the consultant's finding that a
more objective and comprehensive competitive analysis at that time
"might have indicated a benefit for restarting" the Plant; and that
those decisions resulted in Maine Yankee incurring $95.9 million in
"unreasonable" costs. The Company has expensed its share of these
costs. On October 24, 1997, the MPUC issued a Notice of Investigation
initiating an investigation of the shutdown decision and of the
operation of the Plant prior to shutdown, and announced that it had
directed its consultant to extend its review to include those areas. The
Company does not know how the MPUC plans to use the consultant's report,
but believes the report's negative conclusions are unfounded and may be
contradictory. The Company believes it would have substantial
constitutional and jurisdictional grounds to challenge any effort in an
MPUC proceeding to alter wholesale Maine Yankee rates made effective by
the FERC. On November 7, 1997, Maine Yankee and Central Maine Power
initiated a legal challenge to the MPUC investigation in the Maine
Supreme Judicial Court alleging that such an investigation falls
exclusively within the jurisdiction of the FERC and that the MPUC
investigation is therefore barred on constitutional grounds. The
Company joined in this appeal. The MPUC subsequently stayed its
investigation pending the outcome of Maine Yankee's FERC rate case,
while indicating that its consultant would continue its extended review.
The Maine Supreme Court, on motions of the parties, stayed the appeal
pending resolution of the FERC proceeding.
During 1997, the Company incurred Maine Yankee replacement power
costs of approximately $7,302,000, of which $2,324,000 has been deferred
under the Company's rate stabilization plan, and also incurred
-10-
Form 10-K
PART I
Item 1. Business - Continued
additional operating costs of approximately $3.0 million associated with
the efforts to restart and subsequently close Maine Yankee, which have
adversely impacted the Company's earnings.
The February 1, 1998, rate increase, as described in Item 3(g) of
the "Legal Proceedings" section of this Form 10-K, included a portion of
these recoverable 1997 Maine Yankee replacement power costs with the
remaining costs included in the February 1, 1999 rate increase.
However, the collection of future Maine Yankee replacement power costs
will be subject to the MPUC's previously-mentioned prudence review of
the prudency of closing Maine Yankee.
The Company also owns 7.49% of the Common Stock of Maine Electric
Power Company, Inc. (MEPCO). MEPCO owns and operates a 345-KV
(kilovolt) transmission line about 180 miles long which connects the New
Brunswick Power (NB Power) system with the New England Power Pool. The
MEPCO transmission line is also the path by which Wyman No. 4 energy is
delivered northerly into the NB Power system and then wheeled to the
Parent Company through its interconnection with NBEPC at the
international border.
On December 23, 1997, the Company announced the signing of three
separate energy agreements to purchase firm energy and capacity from
Hydro-Quebec (H-Q) and Alternative Energy, Inc.'s Beaver Power Plant in
Ashland, Maine (AEI) for the replacement of Maine Yankee power, and to
market surpluses in partnership with Cinergy, an electric utility
headquartered in Cincinnati, Ohio. However, the Company and H-Q were
unable to agree on final terms and conditions and agreed to terminate
their energy agreement effective March 13, 1998. The Company is
negotiating an agreement with NB Power to supply additional energy not
provided by AEI to service our customers. The Company and Cinergy will
continue their efforts to jointly market available power in Maine and
New England.
-11-
Form 10-K
PART I
Item 1. Business - Continued
Executive Officers
The executive officers of the registrant are as follows:
Office
Continuously
Name Age Held Since
Paul R. Cariani President and Chief 57 6/1/94
Executive Officer
Frederick C. Bustard Vice President, 60 6/1/96
Power Supply & Environment
Larry E. LaPlante Vice President, 46 6/1/96
Finance, Administration and Treasurer
Stephen A. Johnson Vice President, 50 6/1/90
Customer Service and
General Counsel
Secretary and Clerk
Paul R. Cariani has been an employee of the Company since November
1, 1977, starting as an Assistant to the Treasurer. In May 1978, he was
appointed Assistant Treasurer until his election as Treasurer, Secretary
and Clerk, on March 1, 1983. In May 1985, he was elected Vice
President-Finance and Treasurer effective June 1, 1985. On February 25,
1992, Mr. Cariani was elected a Director of the Company to fill an
existing vacancy on the Board. On May 11, 1993, he was elected
Executive Vice President, Chief Financial Officer and Treasurer,
effective June 1, 1993. Effective June 1, 1994, he was elected
President and CEO, replacing the retiring G. Melvin Hovey. Mr. Hovey
remains Chairman of the Board of Directors.
Frederick C. Bustard was elected to the position of Vice President,
Power Supply & Environment effective June 1, 1996. He has been a full-
time employee of the Company since June 15, 1959 in various engineering
capacities until July 1, 1980, when he was appointed Assistant to the
President. On June 1, 1983, he was elected Vice President, Engineering
& Operations. On September 1, 1988, he was elected to the new position
of Vice President of Customer Service and Division Operations, a
position he held until his reappointment to Vice President of
Engineering & Operations on June 1, 1990.
-12-
Form 10-K
PART I
Item 1. Business - Continued
Larry E. LaPlante was elected to the position of Vice President,
Finance, Administration and Treasurer on June 1, 1996. He has been an
employee of the Company since November 4, 1983, starting as Controller.
In May, 1984, he was also appointed Assistant Secretary and Assistant
Treasurer until his election as Vice President, Finance and Treasurer
effective June 1, 1994.
Stephen A. Johnson was elected to the new position of Vice
President, Customer Service and General Counsel, effective June 1, 1990.
Mr. Johnson also continues in his capacity as Secretary and Clerk of the
Company, a position he has held since June 1, 1985. Mr. Johnson was
appointed General Counsel of the Company on March 5, 1985. On September
1, 1988, he was elected Vice President of Administration and General
Counsel, a position he held until his election as Vice President,
Customer Service and General Counsel. Prior to joining the Company Mr.
Johnson was the General Counsel of the Maine Public Advocate Office from
1983 to 1985 and prior to that was a Staff Attorney of the Maine Public
Utilities Commission.
Each executive office is a full-time position and has been the
principal occupation of each officer since first elected. All officers
were elected to serve until the next annual election of officers and
until their successors shall have been duly chosen and qualified. The
next annual election of officers will be on May 12, 1998.
There are no family relationships among the executive officers.
-13-
Form 10-K
PART I
Item 2. Properties
The Company owns and operates electric generating facilities
consisting of: oil-fired steam units with a total capability of 23,000
kilowatts, diesel generation totaling 12,300 kilowatts, and hydro-
electric facilities of 2,300 kilowatts. The Subsidiary owns and
operates a hydro-electric plant of 33,500 kilowatts and a small diesel
unit with 1,000 kilowatt capacity. As discussed in Items 3(a) and (b)
of the "Legal Proceedings" section of this Form 10-K, the Company is
proceeding with the sale of generating assets in accordance with the
State's new electric deregulation law.
The Board of Directors authorized placing on inactive status Steam
Units 1 and 2 of the Company's Caribou Generating Facility in Caribou,
Maine effective January 1, 1996 and were expected to remain inactive for
five years or longer. These two units, which represent 23 MW of
capacity, have become surplus to the Company's needs due to the closure
of Loring Air Force Base and the loss in 1996 of the Company's largest
customer, the Houlton Water Company. During the Units' inactive period,
the plant equipment will be protected and maintained by the installation
of a dehumidification system that will permit the Plant to return to
service in approximately six months.
Steam Unit No. 1 went into operation in the early 1950s and Unit
No. 2, in the mid 1950s. The Company still has a diesel generation
station of approximately 7 MW and a hydro facility of approximately 1 MW
and will continue to employ 11 employees at the Caribou facility.
As of December 31, 1997, the Company and Subsidiary had
approximately 443 pole miles of transmission lines and the Company owned
approximately 1,608 miles of distribution lines.
The Company is a part-owner of a 600,000 kilowatt oil-fired steam
unit built by Central Maine Power Company at its Wyman Station in
Yarmouth, Maine. The Company's share of that unit is 3.3455%, or
approximately 20,000 kilowatts.
Substantially all of the properties owned by the Company are
subject to the liens of the First and Second Mortgage Indentures and
Deeds of Trust.
-14-
Form 10-K
PART I
Item 3. Legal Proceedings
(a) Restructuring of Maine's Electric Utility Industry.
In the Company's Form 10-K for December 31, 1996 as well as
the Form 10-Q for the quarter ended June 30, 1997, the Company
described electric utility restructuring efforts in Maine,
including the Maine Public Utilities Commission's (MPUC)
recommendation to the legislature. After months of hearings
and deliberations, the Maine legislature passed L.D. 1804, "An
Act to Restructure the State's Electric Industry", which the
Governor signed into law on May 29, 1997.
The principal provisions of the new law are as follows:
1) Beginning on March 1, 2000, all consumers of electricity
have the right to purchase generation services directly from
competitive electricity suppliers who will not be subject to
rate regulation.
2) By March 1, 2000, the Company, Central Maine Power
Company (CMP) and Bangor Hydro-Electric Company (BHE) must
divest of all generation related assets and business functions
except for:
(a) contracts with qualifying facilities, such as the
Company's power contract with Wheelabrator-Sherman (W-S),
and conservation providers;
(b) nuclear assets, namely, the Company's investment in
the Maine Yankee Atomic Power Company, however, the MPUC
may require divestiture on or after January 1, 2009;
(c) facilities located outside the United States, i.e.,
the Company's hydro facility in New Brunswick, Canada;
and
(d) assets that the MPUC determines necessary for the
operation of the transmission and distribution services.
The MPUC can grant an extension of the divestiture deadline if
the extension will improve the selling price. For assets not
divested, the utilities are required to sell the rights to the
energy and capacity from these assets. See item (b) below
regarding the divestiture of the Company's generating assets.
3) Billing and metering services will be subject to
competition beginning March 1, 2002, but permits the MPUC to
establish an earlier date, no sooner than March 1, 2000.
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Form 10-K
PART I
Item 3. Legal Proceedings - Continued
4) The Company, through an unregulated affiliate, may market
and sell electricity both within and outside its current
service territory, without limitation. Both CMP and BHE are
limited to 33% of the load within their respective service
territories, but may sell an unlimited amount outside their
service territories. Consumer-owned utilities are allowed to
market and sell within their service territories, but the MPUC
can limit or prohibit competition in their service territory,
if the tax-exempt status of the consumer-owned utility is
threatened.
5) The Company, through a regulated affiliate, will continue
to provide transmission and distribution services which will
be subject to continued regulation by the MPUC.
6) Maine electric utilities will be permitted a reasonable
opportunity to recover legitimate, verifiable and unmitigable
costs that are otherwise unrecoverable as a result of retail
competition in the electric utility industry. The MPUC shall
determine these stranded costs by considering:
a) the utility's regulatory assets related to
generation, i.e., the Company's unrecovered Seabrook
investment;
b) the difference between net plant investment in
generation assets compared to the market value for those
assets; and
c) the difference between future contract payments and
the market value of the purchased power contracts, i.e.,
the W-S contract.
By July 1, 1999, the MPUC will have estimated the stranded
costs for the Company and the manner for the collection of
these costs by the transmission and distribution company.
Customers reducing or eliminating their consumption of
electricity by switching to self-generation, conversion to
alternative fuels or utilizing demand-side management measures
cannot be assessed exit or entry fees. The Company estimates
its stranded costs to be approximately $85 million, based on
the completion of the W-S contract restructuring, market power
estimates beyond 2000 and regulatory treatment of the
Company's remaining Seabrook investment, but does not include
any benefits from the Company's sale of generating assets.
The MPUC shall include in the rates charged by the
-16-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
transmission and distribution utility decommissioning expenses
for Maine Yankee. In 2003 and every three years thereafter
until the stranded costs are recovered, the MPUC shall review
and revaluate the stranded cost recovery.
7) All competitive providers of retail electricity must be
licensed and registered with the MPUC and meet certain
financial standards, comply with customer notification
requirements, adhere to customer solicitation requirements and
are subject to unfair trade practice laws. Competitive
electricity providers must have at least 30% renewable
resources in their energy portfolios, including hydro-electric
generation.
8) A standard-offer service will be available, ensuring
access for all customers to reasonably priced electric power.
Unregulated affiliates of CMP and BHE providing retail
electric power are prohibited from providing more than 20% of
the load within their respective service territories under the
standard offer service, while any unregulated affiliate of the
Company does not have a similar restriction.
9) Unregulated affiliates of CMP and BHE marketing and
selling retail electric power must adhere to specific codes of
conduct, including, among others:
a) employees of the unregulated affiliate providing
retail electric power must be physically separated from
the regulated distribution affiliate and cannot be
shared;
b) the regulated distribution affiliate must provide
equal access to customer information;
c) the regulated distribution company cannot
participate in joint advertising or marketing programs
with the unregulated affiliate providing retail electric
power;
d) the distribution company and its unregulated
affiliated provider of retail electric power must keep
separate books of accounts and records; and
(e) the distribution company cannot condition or tie the
provision of any regulated service to the provision of
-17-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
any service provided by the unregulated affiliated
provider of electricity.
The MPUC shall determine the extent of separation
required in the case of the Company to avoid cross-
subsidization and shall consider all similar relevant
issues as well as the Company's small size.
10) Employees, other than officers, displaced as a result of
retail competition will be entitled to certain severance
benefits and retraining programs. These costs will be
recovered through charges collected by the regulated
distribution company.
11) Other provisions of the new law include provisions for:
a) consumer education;
b) continuation of low-income programs and demand side
management activities;
c) consumer protection provisions;
d) new enforcement authority for the MPUC to protect
consumers.
The MPUC will conduct several rulemaking proceedings
associated with the new restructuring law. The Company is
presently reviewing its business operations and the
opportunities that the new restructuring law presents.
(b) Maine Public Service Company, Divestiture of Generation
Assets, MPUC Docket No. 97-670
As reported in item (a) above, the Company is required to
obtain the MPUC's approval of a plan to divest itself of all
its generation assets by January 1, 1999. On September 9,
1997, the Company, pursuant to this Legislation, submitted to
the MPUC its plan for divesting itself of all its power
entitlements and generation assets, including its Canadian
subsidiary. A hearing was held on this plan on December 18,
1997. By Order issued February 20, 1998, the MPUC approved
the Company's plan and ordered it to proceed to divest itself
of its generation assets in accordance with the plan.
Any final sale of the Company's generation assets must be
approved by the MPUC. In its Order approving the divestiture
-18-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
plan, the MPUC noted a number of concerns that it would
address when the final sale was brought before it for
approval. These concerns included whether the sale of the
assets of the Canadian subsidiary should be delayed pending
the development of a retail market for electricity in Canada
or until the MPUC completes its final study on the efficiency
of competitive markets in northern Maine (see item (c) below)
and whether any sale would create, or exacerbate, a
concentration of generation market power to the detriment of
MPS's customers.
MPS has received and reviewed bids for its generation assets
and power entitlements and is now in the process of
negotiating the terms of sale with the successful bidders.
The Company cannot predict the exact terms of any final sale
of these properties nor whether, or under what terms, that
sale will be approved by the MPUC.
(c) Interim Report by the Maine Public Utilities Commission and
the Maine Attorney General Regarding Market Power Issues
Raised by the Prospect of Retail Competition in the Electric
Industry, MPUC Docket No. 97-877
The Legislation described in item (a) above required the Maine
Department of the Attorney General and the MPUC to jointly
conduct a study of the various market power issues presented
by the introduction of retail competition into Maine's
electric utility industry. A final report in this matter is
due by December 31, 1998. On February 2, 1998, the MPUC and
the Attorney General issued its interim report in this matter.
This interim report did not reach any final conclusion or make
any recommendations, but did note certain areas of concern.
Among the principal areas of concern are:
- whether the proposed regulation of transactions between
a utility and its marketing affiliate will be sufficient
to prevent market dominance by the affiliate or whether
an outright ban on affiliate marketing is preferable.
- that "special circumstances" in the Company's service
territory (such as its direct physical isolation from the
New England power grid) indicates that it may be subject
to a high degree of market power. Accordingly, the
interim report noted, without further elaboration, that
-19-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
the Final Report would "evaluate several possible
legislative adjustments".
In a related matter, and again as required by the Legislation
described in item (a), the MPUC, on January 26, 1998, opened
an investigation into the feasibility of a direct physical
interconnection between the Company's service territory and
the New England power grid (MPUC Docket No. 97-586). The MPUC
expects to issue a draft report on this matter by December 1,
1998. The Company will be directly involved in this
investigation.
The Company cannot at this time predict either the ultimate
conclusions of the studies described above or the effect of
these studies upon the proposed sale of the Company's
generation assets or the prospect of retail competition in the
Company's service territory.
(d) Maine Public Service Company, Request For Open Access
Transmission Tariff, FERC Docket No. ER 95-836-000.
On March 31, 1995, the Company filed an open access
transmission tariff with the Federal Energy Regulatory
Commission (FERC). This tariff provides fees for various
types and levels of transmission and transmission-related
services that are required by transmission customers. The
tariff, as filed, substantially increases some of the fees for
transmission services and provides separate fees for various
transmission-related services. On May 31, 1995, the FERC
approved the filed tariff, subject to refund. The filing has
been vigorously contested by the Company's wholesale
customers. On May 31, 1996, the FERC issued Order 888, a
final rule on open transmission access and stranded cost
recovery. As a result the Company has refiled its tariff to
comply with the Order. A decision by the FERC regarding the
fees under the Company's tariff is not expected until later in
1998. The Company cannot predict the FERC's ultimate decision
in this matter.
(e) Restructured Purchase Power Agreement with Wheelabrator-
Sherman
The Company has a Power Purchase Agreement (PPA) with the
Wheelabrator-Sherman Energy Company (W-S) under which the
Company is obligated to purchase the entire output (up to
126,582 MWH) of a 17.6 MW biomass plant owned by W-S. The
-20-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
current term of the PPA runs through December 31, 2000 and may
be renewed by either party for an additional fifteen years at
prices to be determined by mutual agreement or, absent mutual
agreement, by the MPUC.
On October 15, 1997, the Company and W-S agreed to amend the
PPA. Under the terms of this amendment, W-S has agreed to
reductions in the price of purchased power of approximately
$10 million over the PPA's current term in exchange for up-
front payments of $8.7 million. The Company and W-S have also
agreed to renew the PPA for an additional six years at agreed-
upon prices. The Company believes the amended PPA will help
relieve the financial pressure caused by the recent closure of
Maine Yankee as well as the need for substantial increases in
its retail rates, and is therefore in the best interests of
the Company, its customers and shareholders.
In order to finance the upfront payment to W-S, the Company
concluded that it must obtain funds from the Finance Authority
of Maine (FAME); absent FAME financing the Company does not
believe it can obtain the funds on terms sufficiently economic
to justify the arrangement with W-S. The amended PPA must be
approved by the MPUC if FAME financing is to be obtained. The
Company's request for this approval was given the MPUC Docket
No. 97-727. The Company also asked the MPUC for a
determination that any so-called stranded costs created by the
amended PPA will be recoverable from customers to the extent
permitted by Maine law.
On December 22, 1997, the MPUC approved the amended PPA and
determined that the additional costs created by the amended
PPA will be treated as stranded cost. On February 19, 1998,
the FAME Board of Directors voted to provide the Company with
the financing necessary to support the amended PPA. The
Company is now in the process of negotiating the precise terms
of this financing and expects to actually implement the
restructured PPA by May 1, 1998, but cannot predict the exact
timing or the terms and conditions of the necessary financing.
(f) Maine Public Utilities Commission Investigation of the
Operation and Shutdown of Maine Yankee Atomic Power Company
Generating Facility in Wiscasset, Maine, MPUC Docket No. 97-
781
On October 24, 1997, the MPUC issued a Notice of Investigation
regarding the August, 1997 shutdown of the Maine Yankee Power
-21-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
Plant (see Item 1. "Subsidiaries and Affiliated Companies",
above). The MPUC stated that the "permanent shutdown of the
plant presents significant ratemaking issues" such as
replacement power costs and stranded cost issues, for all
three of Maine Yankee's Maine owners. The announced scope of
the investigation is therefore intended to focus on "two
separate generic prudence questions .... presented in
determining the reasonableness of increased purchased power
costs and reasonableness of the recovery of the unamortized
Maine Yankee investment:
1. Was the decision to shut down the Maine Yankee Plant
prudent?
2. Was the plant prematurely shut down because the plant had
been operated or was operating imprudently?"
As an owner of Maine Yankee, the Company was made a party to
this investigation.
The Company believes the MPUC's jurisdiction over Maine Yankee
costs and prudence issues is preempted by the Federal Power
Act and FERC jurisdiction. If, however, the MPUC should
successfully assert jurisdiction over these issues and, if it
disallowed substantial amounts of the Maine Yankee-related
expenses in retail rates, the effect on the Company's
financial condition would be material and adverse. On
November 7, 1997, Central Maine Power and Maine Yankee
initiated legal challenges to the MPUC investigation in the
Maine Supreme Judicial Court alleging that such an
investigation falls exclusively within the jurisdiction of the
FERC, and that the MPUC's investigation is therefore barred on
constitutional grounds. The Company joined that appeal on
November 13, 1997.
On December 2, 1997, the MPUC issued an Order staying the
investigation. The MPUC noted that Maine Yankee had begun a
rate proceeding before the FERC on November 6, 1997, which
could address the prudence issues raised in the MPUC's own
investigation. The MPUC therefore stayed its investigation in
order "to avoid unnecessary duplicative efforts by all parties
involved". The MPUC reserved the right to reopen the
investigation particularly if FERC declines to address the
prudence issues of concern to the MPUC "if we feel it
necessary to investigate those matters after the FERC
proceeding ends." The Company cannot therefore predict
-22-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
whether the MPUC will reopen its investigation once the FERC
proceeding is concluded.
As a result, the Maine Supreme Judicial Court, on December 15,
1997, upon motion by Maine Yankee and its Maine owners, stayed
all proceedings in the appeal until the first to occur of
either December 31, 1998 or the 30th day after the conclusion
of the FERC's investigation.
(g) Maine Public Utilities Commission Approves Rate Increase
Pursuant to Previously Approved Rate Plan, MPUC Docket
No. 97-830.
Reference is made to the Company's Form 10-K for December 31,
1996 where the Company's rate stabilization plan approved by
the Maine Public Utilities Commission (MPUC) (Docket No. 95-
052) in November, 1995 is described. In addition, in the
Company's Form 8-K filed November 19, 1997, the Company
announced its annual filing under the rate plan.
On November 13, 1997, the Company filed with the MPUC its
annual rate increase pursuant to the Company's rate plan. The
filing supported an annual increase in retail rates of 7.6%
effective February 1, 1998 consisting of the following:
- 2.75% specified annual increase provided in the rate
plan;
- 2.22% increase for 50% of the Maine Yankee replacement
power costs in accordance with the Maine Yankee plant
outage provisions of the rate plan; and
- 2.63% increase in accordance with the profit-sharing
mechanism of the rate plan since earnings for the review
period, i.e. the twelve months ended September 30, 1997,
were more than 300 basis points below the target return
on equity.
Additional capacity payments to restart Maine Yankee and
incremental replacement power costs have adversely impacted
the Company's 1997 earnings and triggered the rate plan
profit-sharing mechanism noted above. The Company's ability
to increase its rates for the profit-sharing and for 50% of
Maine Yankee replacement power costs is subject to the MPUC's
pending review of the prudency of the decision to close Maine
Yankee (see item (f) above).
-23-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
In addition, the Company had amended its November, 1997 filing
requesting that the savings from the restructured
Wheelabrator-Sherman (W-S) Contract, as approved by the MPUC
on December 22, 1997 (see item (e) above) be used to offset
future Maine Yankee replacement power costs. However, this
treatment was again subject to the results of the MPUC's
review of the prudency of closing Maine Yankee. The
restructuring of the W-S Contract requires an up-front payment
of approximately $8.7 million, which the Company intends to
finance from funds obtained from the Finance Authority of
Maine (FAME), under its rate stabilization program.
On January 15, 1998, the Public Advocate and the Company, with
the support of the MPUC Staff, reached an agreement on the
rate increase for February 1, 1998. The principal elements of
the stipulation are as follows:
- the rate increase effective February 1, 1998 was 3.9%,
consisting of the specified increase of 2.75% and
approximately $562,000 of the 1997 recoverable Maine
Yankee replacement power costs (1.15%);
- the minimum rate increase effective February 1, 1999 will
be 3.1%, consisting of a specified increase of 2% and the
remaining recoverable 1997 Maine Yankee replacement power
costs of $523,000;
- Maine Yankee replacement power costs for the period
October 1, 1997 through September 30, 1998 will be offset
by the 1998 savings under the restructured W-S contract,
with the recovery of any incremental Maine Yankee
replacement power costs subject to a final order by the
MPUC in its previously mentioned review of the prudency
of closing Maine Yankee;
- the Company wrote off in 1997 unamortized Maine Yankee
refueling outage costs of approximately $1,458,000;
- the Company waives its right to collect additional revenues for
the profit-sharing review period, i.e. the twelve months ended
September 30, 1997, since the earnings deficiency was the result
of the closing of Maine Yankee and, based on the 3.9% increase
granted by the MPUC, the Company expects to earn a reasonable
rate of return in 1998 without these additional revenues;
- a customer service and reliability standards penalty will
be suspended pending review of these standards during the
rate plan's mid-term review in September of 1998.
-24-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
This agreement was approved by the MPUC on January 26, 1998.
The Company was not able to attain its interest coverage tests
for the fourth quarter of 1997, but the Banks have granted a
waiver. For 1998, the Banks have agreed to amend these
interest coverage tests to deal with these additional Maine
Yankee costs. Based on the Company's current projections, the
Company believes that it can attain these amended interest
coverage tests. The Company believes that its rate plan deals
effectively with the closing of Maine Yankee, with customers
and shareholders sharing the burden equally. However, the
Company cannot predict what the MPUC's decisions will be
concerning the prudency of closing Maine Yankee. If the
Company is adversely impacted by the MPUC prudency decision,
or if the Company is unable to complete the financing for the
restructured Wheelabrator-Sherman contract, the Company may be
required to seek an emergency rate increase and will review
all cash expenditures, including the level of dividends.
-25-
Form 10-K
PART I
Item 4. Submission of Matters To a Vote of Security Holders
At the Company's Annual Meeting of Stockholders, held on
May 13, 1997, the only matter voted upon was the
uncontested election of the following directors to serve
until the 2000 Annual Meeting of Stockholders, each of
whom received the votes shown:
Non-votes and
Nominee For Against Abstentions
Robert E. Anderson 1,320,381 49,395 247,474
Nathan L. Grass 1,320,279 49,497 247,474
J. Paul Levesque 1,319,315 50,461 247,474
-26-
Form 10-K
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters
The Company's Common Stock is listed and traded on the
American Stock Exchange. As of December 31, 1997, there were
1,436 holders of record of the Company's Common Stock.
Dividend data and market price related to the Common Stock are
tabulated as follows for the two most recent calendar years:
Dividends
Market Price Dividends Declared
High Low Paid Per Share Per Share
1997
First Quarter $18-3/8 $14-1/8 $ .46 $ .25
Second Quarter $14-3/4 $11-3/8 .25 .25
Third Quarter $12-7/8 $10-3/16 .25 .25
Fourth Quarter $12-13/16 $11-3/8 .25 .25
Total Dividends $1.21 $1.00
1996
First Quarter $22-3/8 $19 $ .46 $ .46
Second Quarter $20-3/8 $16-7/8 .46 .46
Third Quarter $19-1/8 $17-3/8 .46 .46
Fourth Quarter $19-1/2 $17-1/8 .46 .46
Total Dividends $1.84 $1.84
Dividends declared within the quarter are paid on the first day of
the succeeding quarter.
See Note 7 to the financial statements incorporated herein by
reference concerning restrictions on payment of dividends on
Common Stock.
Item 6. Selected Financial Data
A five-year summary of selected financial data (1993-1997) is
included on page 13 of the Company's 1997 Annual Report to
Stockholders, which summary is incorporated herein by
reference.
-27-
Form 10-K
PART II
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
The information required to be furnished in response to this
Item is submitted as pages 4 to 12, Exhibit 13, 1997 Annual
Report to Shareholders, which pages are hereby incorporated
herein by reference. Information regarding "Construction" is
also furnished in Note 10, "Commitments, Contingencies, and
Regulatory Matters", of the Notes to the Consolidated
Financial Statements, pages 25 to 29 of the 1997 Annual Report
to Shareholders, which pages are hereby incorporated herein by
reference.
-28-
Form 10-K
PART II
Item 8. Financial Statements and Supplementary Data
(a) The following financial statements and supplementary
data are included in the Company's 1997 Annual Report to
Stockholders on pages 14 through 29 and page 34, and are
incorporated herein by reference:
Statements of Consolidated Operations for the years
ended December 31, 1997, 1996 and 1995.
Statements of Consolidated Cash Flows for the years
ended December 31, 1997, 1996 and 1995.
Consolidated Balance Sheets as of December 31, 1997
and 1996.
Statements of Consolidated Common Shareholders'
Equity for the years ended December 31, 1997, 1996
and 1995.
Consolidated Statements of Capitalization as of
December 31, 1997 and 1996.
Notes to Consolidated Financial Statements.
Independent Accountants' Report.
Item 9. Changes In And Disagreements With Accountants On
Accounting and Financial Disclosure
For many years, including fiscal year 1995, the firm of Deloitte &
Touche, LLP, (Deloitte & Touche) independent public accountants, was
engaged by the Company as the principal independent accountant to
audit the Company's financial statements. On March 1, 1996, the
Company's entire Board of Directors, based on a recommendation of the
Audit Committee of the Board, voted to engage the firm of Coopers &
Lybrand, L.L.P., (Coopers & Lybrand) independent public accountants,
as the Company's principal accountant beginning with the 1996 fiscal
year audit and not to use the services of Deloitte & Touche. This
change in accountants followed the Company's issuance, in November
1995, of a request for proposal to six major independent accounting
firms to audit the Company's financial statements. The Company issued
this request solely to determine whether it could reduce the fees it
pays for accounting services. Three firms, including Deloitte &
Touche and Coopers and Lybrand, responded to the request. Based
solely upon the Audit Committee's review of those responses, and the
terms of the request, the Board determined to engage Coopers &
Lybrand, whose bid was substantially lower than any
-29-
Form 10-K
PART II
Item 9. Changes In And Disagreements With Accountants On
Accounting and Financial Disclosure - Continued
other received by the Company, as the Company's principal
accountant for a term of at least three years, beginning in
fiscal year 1996. As a result of this vote, the Company
informed Deloitte & Touche that it would not renew its year to
year engagement letter with that firm.
Deloitte & Touche's report on the Company's financial
statements for fiscal year 1995 did not contain an adverse
opinion or disclaimer of opinion or any modification or
qualification.
At no time during the Company's two most recent fiscal years
of Deloitte & Touche's engagement or any time thereafter has
there been any disagreement between the Company and the firm
on any matter of accounting principles or practices, financial
statement disclosure or auditing scope or procedure. At no
time during the Company's two most recent fiscal years of
Deloitte & Touche's engagement or any time thereafter did any
event occur between the Company and the firm that would
require further reporting in this Form 10-K.
At no time during the Company's two most recent fiscal years
of Deloitte & Touche's engagement and any time thereafter
prior to the Company's engaging Coopers & Lybrand did the
Company consult Coopers & Lybrand regarding either the
application of accounting principles to a specified
transaction, either completed or proposed, or the type of
audit opinion that might be rendered on the Company's
financial statements.
-30-
Form 10-K
PART III
Item 10. Directors and Executive Officers of the Registrant
Information with regard to the Directors of the registrant is
set forth in the proxy statement of the registrant relating to
its 1998 Annual Meeting of Stockholders, which information is
incorporated herein by reference. Certain information
regarding executive officers is set forth under the caption
"Executive Officers" in Item 1 of Part I of this Form 10-K and
also in the proxy statement of the registrant relating to the
1998 Annual Meeting of Stockholders, under "Compliance with
Section 16(a) of the Securities and Exchange Act of 1934",
which information is incorporated by reference.
Item 11. Executive Compensation
Information for this item is set forth in the proxy statement
of the registrant relating to its 1998 Annual Meeting of
Stockholders, which information (with the exception of the
"Board Executive Compensation Committee Report") is
incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and
Management
Information for this item is set forth in the proxy statement
of the registrant relating to its 1998 Annual Meeting of
Stockholders, which information is incorporated herein by
reference.
Item 13. Certain Relationships and Related Transactions
Not applicable.
-31-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K
(a) (1) Financial Statements
Incorporated by reference into Part II of this
report from pages 14 through 29 and page 34 of the
1997 Annual Report to Stockholders:
Statements of Consolidated Operations for years
ended December 31, 1997, 1996 and 1995.
Statements of Consolidated Cash Flows for the years
ended December 31, 1997, 1996 and 1995.
Consolidated Balance Sheets as of December 31, 1997
and 1996.
Statements of Consolidated Common Shareholders'
Equity for the years ended December 31, 1997, 1996
and 1995.
Consolidated Statements of Capitalization as of
December 31, 1997 and 1996.
Notes to Consolidated Financial Statements.
Independent Accountants' Report.
(2) Financial Statement Schedules
Included in Part IV of this report:
-32-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
Page
Report of Independent Public Accountants 43
Schedule II - Valuation of Qualifying Accounts 44
and Reserves
Schedules other than those listed above are omitted for the
reason that they are not required or are not applicable, or
the required information is shown in the financial statements
or notes thereto.
(3) Exhibits
Certain of the following exhibits are filed
herewith. Certain other of the following exhibits
have heretofore been filed with the Commission and
are incorporated herein by reference. (* indicates
filed herewith).
3(a) Restated Articles of Incorporation with all
amendments through May 8, 1990. (Exhibit 3(a)
to 1990 form 10-K)
3(b) By-laws of the Company, as amended through May
12, 1987. (Exhibit 3(b) to 1987 Form 10-K)
4(a) Indenture of Mortgage and Deed of Trust
defining the rights of the holders of the
Company's First Mortgage Bonds. (Exhibit 4(a)
to 1980 Form 10-K)
4(b) First Supplemental Indenture. (Exhibit 4(b)
to 1980 Form 10-K)
4(c) Second Supplemental Indenture. (Exhibit 4(c)
to 1980 Form 10-K)
4(d) Third Supplemental Indenture. (Exhibit 4(d)
to 1980 Form 10-K)
4(e) Fourth Supplemental Indenture. (Exhibit 4(e)
to 1980 Form 10-K)
4(f) Fifth Supplemental Indenture. (Exhibit A to
Form 8-K dated May 10, 1968)
4(g) Sixth Supplemental Indenture. (Exhibit A to
Form 8-K dated April 10, 1973)
-33-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
4(h) Seventh Supplemental Indenture. (Exhibit A to
Form 8-K dated November 7, 1975)
4(i) Eighth Supplemental Indenture. (Exhibit 4(i)
to 1980 Form 10-K)
4(j) Ninth Supplemental Indenture. (Exhibit B to
Form 10-Q for the second quarter of 1978)
4(k) Tenth Supplemental Indenture. (Exhibit 4(k)
to 1980 Form 10-K)
4(l) Eleventh Supplemental Indenture. (Exhibit
4(l) to 1982 Form 10-K)
4(m) Indenture defining the rights of the holders
of the Company's 9 7/8% debentures. (Exhibit
A to Form 8-K, dated June 10, 1970)
4(n) Indenture defining the rights of the holders
of the Company's 14% debentures. (Exhibit
4(n) to 1982 Form 10-K)
4(o) Twelfth Supplemental Indenture. (Exhibit 4(o)
to Form 10-Q for the quarter ended September
30, 1984)
4(p) Thirteenth Supplemental Indenture. (Exhibit
4(p) to Form 10-Q for the quarter ended
September 30, 1984)
4(q) Fourteenth Supplemental Indenture, Dated July
1, 1985. (Exhibit 4(q) to 1985 Form 10-K)
4(r) Fifteenth Supplemental Indenture, Dated March
1, 1986. (Exhibit 4(r) to 1985 Form 10-K)
4(s) Sixteenth Supplemental Indenture, Dated
September 1, 1991. (Exhibit 4(s) to the
Company's 1991 Form 10-K).
9 Not applicable.
10(a)(1) Joint Ownership Agreement with Public Service
of New Hampshire in respect to construction of
two nuclear generating units designated as
Seabrook Units 1 and 2, together with related
-34-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
amendments to date. (Exhibit 10 to 1980 Form 10-K)
10(a)(2) Twentieth Amendment to Joint Ownership
Agreement (Exhibit 10(a)(6) to the Company's
1986 Form 10-K)
10(a)(3) Twenty-Second Amendment to Joint Ownership
Agreement. (Exhibit 10(a)(3) to the 1988 Form
10-K)
10(b)(1) Capital Funds Agreement, dated as of May 20,
1968 between Maine Yankee Atomic Power Company
and the Company. (Exhibit 10(b)(1) to Form
10-Q for the quarter ended March 31, 1983)
10(b)(2) Power Contract, dated as of May 20, 1968
between Maine Yankee Atomic Power Company and
the Company. (Exhibit 10(b)(2) to Form 10-Q
for the quarter ended March 31, 1983)
10(c)(1) Participation Agreement, as of June 20, 1969,
with Maine Electric Power Company, Inc.
(Exhibit 10(c)(1) to Form 10-Q for the quarter
ended March 31, 1983)
10(c)(2) Agreement, as of June 20, 1969, among the
Company and the other Maine Participants.
(Exhibit 10(c)(2) to Form 10-Q for quarter
ended March 31, 1983)
10(c)(3) Power Purchase and Transmission Agreement
Supplement to Participation Agreement, dated
as of August 1, 1969, with Maine Electric
Power Company, Inc. (Exhibit 10(c)(3) to Form
10-Q for quarter ended March 31, 1983)
10(c)(4) Supplement Amending Participation Agreement,
as of June 24, 1970, with Maine Electric Power
Company, Inc., (Exhibit 10(c)(4) to Form 10-Q
for quarter ended March 31, 1983)
10(c)(5) Second Supplement to Participation Agreement,
dated as of December 1, 1971, including as
Exhibit A the Unit Participation Agreement
dated November 15, 1971, as amended, between
Maine Electric Power Company, Inc. and the New
Brunswick Electric Power Commission. (Exhibit
-35-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
10(c)(5) to Form 10-Q for quarter ended March
31, 1983)
10(c)(6) Agreement and Assignment, as of August 1,
1977, by Connecticut Light & Power Company,
Hartford Electric Company, Holyoke Water Power
Company, Holyoke Power Company, Western
Massachusetts Electric Company and the
Company. (Exhibit 10(c)(6) to Form 10-Q for
the quarter ended March 31, 1983)
10(c)(7) Amendment dated November 30, 1980 to Agreement
and Assignment as of August 1, 1977, between
Connecticut Light & Power Company, Hartford
Electric Company, Holyoke Water Power Company,
Holyoke Power Company, Western Massachusetts
Electric Company and the Company. (Exhibit
10(c)(7) to Form 10-Q for the quarter ended
March 31, 1983)
10(c)(8) Assignment Agreement as of January 1, 1981,
between Central Maine Power Company and the
Company. (Exhibit 10(c)(8) to Form 10-Q for
the quarter ended March 31, 1983)
10(d) Wyman Unit #4 Agreement for Joint Ownership as
of November 1, 1974, with Amendments 1, 2, and
3, dated as of June 30, 1975, August 16, 1976,
December 31, 1978, respectively. (Exhibit
10(d) to Form 10-Q for the quarter ended March
31, 1983)
10(e) Agreement between Sherman Power Company and Maine
Public Service Company, dated June 4, 1984, with
amendments dated July 12, 1984 and February 14, 1985.
(Exhibit 10(f) to 1984 Form 10-K)
10(f) Credit Agreement, dated as of October 8, 1987 among the
Registrant and The Bank of New York, Bank of New
England, N.A., The Merrill Trust Company and The Bank
of New York, as agent for the Participating Banks
(Exhibit 10(g) to Form 8-K dated October 13, 1987)
10(g) Amendment No. 1, dated as of October 8, 1989,
to the Revolving Credit Agreement, dated as of
October 8, 1987, among the Registrant and The
-36-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
Bank of New York, Bank of New England, N.A.,
Fleet Bank (formerly the Merrill Trust
Company) and The Bank of New York as agent for
the participating banks (Exhibit 10(l) to Form
8-K dated September 22, 1989).
10(h) Amendment No. 2, dated as of June 5, 1992, to
the Revolving Credit Agreement, among the
Registrant and The Bank of New York, Bank of
New England, N.A., Shawmut Bank and the Bank
of New York, as agent for the participating
banks. (Exhibit 10(h) to the Company's 1992
Form 10-K)
10(i) Indenture of Second Mortgage and Deed of
Trust, dated as of October 1, 1985, made by
the Registrant to J. Henry Schroder Bank and
Trust Company, as Trustee. (Exhibit 10(i) to
Form 8-K dated November 1, 1985)
10(j) First Supplemental Indenture Dated March 1,
1991. (Exhibit 10(i) to the Company's 1991
Form 10-K).
10(k) Second Supplemental Indenture Dated September
1, 1991. Exhibit 10(j) to the Company's 1991
Form 10-K).
10(l) Agency Agreement dated as of October 1, 1985,
between J. Henry Schroder Bank and Trust
Company, as Trustee under the Indenture of
Second Mortgage and Deed of Trust dated as of
October 1, 1985, made by the Registrant to J.
Henry Schroder Bank and Trust Company, as
Trustee, and Continental Illinois National
Bank and Trust Company, as Trustee, under an
Indenture of Mortgage and Deed of Trust, dated
as of October 1, 1945, as amended and
supplemented, made by the Registrant to
Continental Illinois National Bank and Trust
Company, as Trustee (Exhibit 10(j) to Form 8-K
dated November 1, 1985)
Executive Compensation Plans and Arrangements
10(m) Employment Contract between Frederick C.
Bustard and Maine Public Service Company dated
-37-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
August 22, 1989. (Exhibit 10(h) to 1989 Form
10-K)
10(n) Employment Contract between Paul R. Cariani
and Maine Public Service Company dated August
22, 1989. (Exhibit 10(l) to 1989 Form 10-K)
10(o) Employment Contract between Stephen A. Johnson
and Maine Public Service Company dated August
22, 1989. (Exhibit 10(m) to 1989 Form 10-K)
10(p) Employment Contract between Larry E. LaPlante
and Maine Public Service Company, dated May 9,
1995.
10(q) Maine Public Service Company, Prior Service
Executive Retirement Plan, dated May 12, 1992.
(Exhibit 10(s) to 1992 Form 10-K).
10(r) Maine Public Service Company Pension Plan.
(Exhibit 10(t) to 1992 Form 10-K).
10(s) Maine Public Service Company Retirement
Savings Plan. (Exhibit 10(u) to 1992 Form 10-
K).
10(t) Third Supplemental Indenture Dated as of June
1, 1996.
10(u) Amendment No. 3, dated as of October 8, 1995,
to the Revolving Credit Agreement, dated as of
October 7, 1987, among the Registrant and The
Bank of New York, Shawmut Bank of Boston,
Fleet Bank of Maine, and The Bank of New York,
an agent for the participating Banks.
11 Not applicable.
12 Not applicable.
*13 1997 Annual Report to Shareholders.
16 March 8, 1996 Letter regarding change in
certifying accountant from Deloitte & Touche LLP
18 Not applicable.
19 Not applicable.
-38-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
21 Maine and New Brunswick Electrical Power
Company, Limited, a Canadian corporation.
22 Not applicable.
23 Not applicable.
99(a) Agreement of Purchase and Sale between Maine
Public Service and Eastern Utilities
Associates, dated April 7, 1986 (Exhibit 28(a)
to Form 10-Q for the quarter ended June 30,
1986).
99(b) Addendum to Agreement of Purchase and Sale,
dated June 26, 1986 (Exhibit 28(b) to Form 10-
Q for the Quarter ended June 30, 1986).
99(c) Stipulation between Maine Public Service
Company, the Staff of the Commission and the
Maine Public Utilities Commission and the
Maine Public Advocate, dated July 14, 1986
(Exhibit 28(c) to Form 10-Q for the quarter
ended June 30, 1986).
99(d) Amendment to July 14, 1986 Stipulation, dated
July 18, 1986 (Exhibit 28(d) to Form 10-Q for
the quarter ended June 30, 1986).
99(e) Order of the Maine Public Utilities Commission
dated July 21, 1986, Docket Nos 84-80, 84-113
and 86-3.
99(f) Order of the Maine Public Utilities
Commission, dated May 9, 1986, Docket Nos. 84-
113 and 86-3 (with attached Stipulations).
(Exhibit 28(r) to 1986 Form 10-K).
99(g) Order of the Maine Public Utilities
Commission, dated July 31, 1987, Docket Nos.
84-80, 84-113, 87-96 and 87-167 (with attached
Stipulation) (Exhibit 28(i) to 1988 Form 10-K).
99(h) Agreement between Maine Public Service Company
and various current Seabrook Nuclear Project
Joint Owners, dated January 13, 1989 (Exhibit
28(o) to 1988 Form 10-K).
-39-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
99(i) Order of the Maine Public Utilities Commission
dated November 30, 1995 (with attached
Stipulation) in Docket No. 95-052. (Exhibit
28(p) to 1995 Form 10-K).
99(j) Order of the Federal Energy Regulatory
Commission dated May 31, 1995 in Docket No. ER
95-836-000. (Exhibit 28(r) to 1995 Form 10-
K).
99(k) Order of Maine Public Utilities Commission
dated June 26, 1996 in Docket 95-052 (Rate
Design)
*99(l) Independent Auditors Report of Deloitte &
Touche L.L.P. dated February 14, 1996
regarding year ended December 31, 1995.
*99(m) Amendment No. 1, dated as of March 28, 1997,
to the Letter of Credit and Reimbursement
Agreement, dated as of June 1, 1996, among the
Registrant, The Bank of New York, Fleet Bank
of Maine, and The Bank of New York, as Agent
and Issuing Bank.
*99(n) Amendment No. 4, dated as of March 28, 1997,
to the Revolving Credit Agreement, dated as of
October 8, 1987, by and among the Registrant,
the signatory Banks thereto and The Bank of
New York, as Agent.
*99(o) Order of Maine Public Utilities Commission
dated January 30, 1998 in Docket No. 97-830
(Annual Increase under Rate Stabilization
Plan).
*99(p) Interim Report of the MPUC and Maine Attorney
General regarding market power issues raised
by the prospect of the retail competition in
the electric industry in Docket No. 97-877.
*99(q) Order by the Maine Public Utilities Commission
dated January 15, 1998 in Docket No. 97-727.
-40-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
(b) A Form 8-K was filed on: January 31, 1997, under item 5,
Other Events; February 14, 1997, under item 5, Other
Events; March 7, 1997, under item 5, Other Events; March
31, 1997, under item 5, Other Events and item 7,
Exhibits; June 4, 1997, under item 5, Other Events;
September 4, 1997, under item 5, Other Events; October
15, 1997, under item 5, Other Events; November 19, 1997,
under item 5, Other Events; December 23, 1997, under item
5, Other Events; and January 28, 1998, under item 5,
Other Events.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized, on the 26th of March, 1998.
MAINE PUBLIC SERVICE COMPANY
By: /s/ Larry E. LaPlante
Larry E. LaPlante
Vice President, Finance,
Administration and Treasurer
-41-
Form 10-K
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons in the
capacities and on the date indicated.
Signature Title Date
Chairman of the Board,
/s/ G. M. Hovey and Director 3/6/98
(G. Melvin Hovey)
/s/ Paul R. Cariani President and Director 3/6/98
(Paul R. Cariani)
/s/ Robert E. Anderson Director 3/6/98
(Robert E. Anderson)
/s/ Donald F. Collins Director 3/6/98
(Donald F. Collins)
/s/ D. James Daigle Director 3/6/98
(D. James Daigle)
/s/ Richard G. Daigle Director 3/6/98
(Richard G. Daigle)
Director
(J. Gregory Freeman)
/s/ Deborah L. Gallant Director 3/6/98
(Deborah L. Gallant)
/s/ Nathan L. Grass Director 3/6/98
(Nathan L. Grass)
/s/ J. Paul Levesque Director 3/6/98
(J. Paul Levesque)
-42-
REPORT OF INDEPENDENT ACCOUNTANTS
To the Directors and Shareholders of
Maine Public Service Company
We have audited the consolidated financial statements of Maine Public
Service Company and its subsidiary, Maine and New Brunswick Electrical
Power Company, Limited, as of December 31, 1997 and 1996, and for the
years then ended, which financial statements are included on pages 14
through 29 of the 1997 Annual Report to Shareholders of Maine Public
Service Company and incorporated by reference herein. We have also
audited the financial statement schedules as of December 31, 1997 and
1996, listed in the index on page 33 of this Form 10-K. These financial
statements and financial statement schedules are the responsibility of
the Company's management. Our responsibility is to express an opinion
on these financial statements and financial statement schedules based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Maine Public Service Company and its subsidiary as of December 31, 1997
and 1996, and the consolidated results of their operations and their
cash flows for the years then ended in conformity with generally
accepted accounting principles. In addition, in our opinion, the
financial statement schedules referred to above, when considered in
relation to the basic financial statements taken as a whole, presents
fairly, in all material respects, the information required to be
included therein.
/s/ Coopers & Lybrand, LLP
Portland, Maine
February 13, 1998
-43-
Maine Public Service Company & Subsidiary
Valuation of Qualifying Accounts & Reserves
For the Years Ended December 31, 1997, 1996, & 1995
Column A Column B Column C Column D Column E
Additions: Deductions:
Balance Recoveries Accounts Balance
at Costs of Accounts Written Off at
Beginning & Previously As End of
Description of Period Expenses Written Off Uncollectible Period
Reserve Deducted From Asset
To Which It Applies:
Allowance for
Uncollectible Accounts
Year Ended December 31:
1997 207,029 182,706 124,397 299,132 215,000
1996 214,130 182,000 102,627 291,728 207,029
1995 214,215 150,800 109,390 260,275 214,130
-44-
Exhibit 13
Maine Public Service Company
1997 Annual Report
We put a lot of energy into Northern Maine
(Page 1)
Maine Public Service Company
(System Map)
The primary goal of Maine Public Service Company is to supply reliable,
economical electrical power to Northern Maine. The Company is an investor-
owned electric utility with a wholly-owned subsidiary, Maine and New
Brunswick Electrical Power Company, Ltd., located at Tinker, New Brunswick.
Together both companies provide energy to more than 35,000 retail customers in
a 3,600 square mile area.
Maine Public Service Company has a favorable mixture of generation
sources made up of power produced by hydro-electric and oil-fueled facilities,
as well as two independent wood-burning cogenerators. The system is
strengthened by electrical interconnections with New Brunswick, Canada,
allowing electrical support from the New Brunswick system and indirectly from
the Hydro-Quebec system.
Major business activities in the area center around the production of
agricultural and forest products. Service was provided at a high reliability
rate over the last year, and it is our aim to meet customer needs fully and
efficiently, at the lowest possible cost.
Table of Contents
Profile and Table of Contents 1
President's Letter 2-3
Analysis of Financial Condition
and Review of Operations - 1997 4-11
Shareholder Information 12
Five-Year Summary of Selected Financial Data 13
Financial Statements and Notes 14-29
Consolidated Financial Statistics 30-31
Consolidated Operating Statistics 32-33
Independent Accountants' Report 34
Directors 35
Executive Officers and Stock
Transfer Information 36
(Photo)
Walter M. Reed, Jr., age 74, died unexpectedly while golfing at Aroostook Valley
Country Club, August 21, 1997. A champion golfer and well-known retired
businessman, Walter served as President of Maine Potato Growers for 22 years.
He had been a Director of Maine Public Service Company since February 28, 1979,
serving on the Pension Investment Committee and Budget and Finance Committee.
With sadness we remember and appreciate the efforts of our valued friend.
Maine Public Service Company
209 State Street
P. O. Box 1209
Presque Isle, Maine 04769-1209
Tel. No. (207) 768-5811 * FAX No. (207) 764-6586
Home Page: http://www.mainerec.com/mpsco.html * E-Mail: mainepub@ mfx.net
(Pages 2 and 3)
(Photo)
Bell-Ringing Ceremony in New York -- With a solid rap on the American Stock
Exchange bell, MPS President Paul R. Cariani, left, opened stock trading at
precisely 9:30 a.m. on December 5, 1997. The event marked the Company's 50th
anniversary of trading on the Exchange. Looking on from Cariani's left are Amex
Senior Vice President Delia Emmons; MPS Vice President of Finance,
Administration, and Treasurer Larry LaPlante; and Amex Executive Vice
President James Duffy. MPS stock is listed on the Amex under the ticker symbol
"MAP".
President's Letter
to our Shareholders and
Employees
The pace of change quickened in 1997 and the year turned out to be one of
the most challenging of your Company's 80-year history. Although we suffered
a loss of $1.35 per share, we have made significant progress in restoring the
financial health of the Company and are moving forward with positive
developments in order to compete under future deregulation. We have increased
our efforts in marketing and economic development.
As you know, the 1994 closure of Loring Air Force Base and the 1996 loss
of our largest customer, Houlton Water Company, have placed continued financial
challenges before us. Greatly compounding our difficulties, the closure of
Maine Yankee in 1997 cost this Company $2.94 per share in 1997 and is the
primary reason for this year's unfavorable financial performance.
Despite these adverse circumstances, the Company has taken several steps
to improve its financial condition; steps that I believe will substantially
improve our results in 1998 and beyond. These developments are:
* Settlement of the third year of our rate plan;
* Restructuring of the Wheelabrator-Sherman power contract;
* Potential sale of our Generation Assets;
* Development of a Marketing Subsidiary; and
* Improved economic development activity within our service territory.
Settlement of Rate Plan
Through negotiations with the MPUC Staff and Public Advocate, we settled
the third year of our rate stabilization plan with a 3.9% rate increase
effective February 1, 1998. As part of the agreement, we wrote off nearly $1.5
million of Maine Yankee expenses in 1997. This rate settlement will improve our
financial position in 1998 and is in the best interest of all concerned. Even
with this rate increase, MPS will continue to be competitive with other
investor-owned utilities throughout New England.
Restructuring Supply Contract
We have recently received approval from the Maine Public Utilities
Commission to buy down and restructure our power supply contract with
Wheelabrator-Sherman. This restructuring will substantially reduce our expenses
beginning 1998. We expect to finance the buy-down through the Finance Authority
of Maine (FAME).
Sale of Generation Assets
The Maine retail access law, passed in 1997, requires an open competitive
market for generation, beginning March 1, 2000. In order to facilitate that
free market, the law requires all electric utilities to divest of generating
assets by March 1, 2000.
In order to take advantage of a currently favorable market in the
Northeast, the Company opened bidding on its generation assets in August, 1997.
Based on preliminary results of the bid process, we are confident we will
receive fair value and look forward to finalizing the sale in 1998. The retail
access law permits electric utilities a reasonable opportunity to recover
legitimate, verifiable and unmitigable costs (otherwise known as stranded costs)
that are unrecoverable as a result of retail competition. We believe the
sale of our generating assets, along with the restructured W-S contract, will
substantially reduce our stranded costs and, thereby, facilitate its recovery.
MPUC proceedings in 1998 will address stranded costs as well as rates and other
restructuring issues. Both the sale of our generating assets and stranded costs
are subject to MPUC approval.
A New Marketing Subsidiary
Changes in electric regulation will present a number of opportunities.
Anticipating retail access, MPS is developing a marketing subsidiary, although
the subsidiary's formation must be approved by the MPUC. We are working with
Cinergy, an electric utility headquartered in Cincinnati, Ohio, to market power.
The marketing group is actively trading wholesale power as well as researching
products and services that may be marketable in an unregulated, competitive
environment.
Economic Development
This year, we will witness the opening of two call centers within our
service territory, one at Loring Commerce Center (former Air Base) and one in
Presque Isle. These new businesses are solid evidence of northern Maine's
emerging economic recovery, along with the restart of a wood-fired generating
plant in our service territory.
We have an agreement in principle with our Banks that satisfies our
interest coverage tests and will restructure our credit agreement. This
agreement resolves issues pertaining to violations of our interest coverage
tests and potential defaults on our debt instruments caused by the closure of
Maine Yankee. Although the loss of Maine Yankee posed a financial hardship for
us, the decision to close the plant was based on an economic analysis of the
costs, risks, and uncertainties of operating the plant compared to closing and
decommissioning the site. As explained elsewhere in this report, the MPUC may
challenge the prudency of this decision.
Overall, I am pleased with the progress of the Company and believe that we
are putting our finances in order and are preparing for retail access. To
summarize, the aforementioned events should allow the Company to maintain
competitive rates, satisfy the financial covenants of our lenders, and maintain
our current dividend, barring any unanticipated developments.
I want to thank you for your trust, confidence, and the opportunity to lead
your Company into the next century. And, as always, our employees continue to
dedicate themselves and exhibit the highest degree of professionalism and work
ethic, and I thank them for that.
Sincerely,
Paul R. Cariani
President and CEO
(Page 4)
Analysis of Financial Condition and Review of Operations - 1997
RESULTS OF OPERATIONS
Operating Revenues and Energy Sales
Consolidated operating revenues and MWH sales for the years 1997, 1996, and
1995 are as follows:
Consolidated Operating Revenues and Megawatt Hours Sold
1997 1996 1995
(Dollars in Thousands) Dollars MWH Dollars MWH Dollars MWH
Residential $20,391 167,368 $19,961 169,298 $19,081 168,640
Commercial & Industrial - Large
9,452 134,741 10,112 134,588 9,437 128,478
Commercial & Industrial - Small
17,419 168,976 16,420 163,804 15,723 165,914
Other Retail 1,468 13,323 1,523 13,166 1,701 14,859
Total Retail 48,730 484,408 48,016 480,856 45,942 477,891
Sales for Resale 2,168 57,578 2,096 55,958 6,955 123,793
Total Primary 50,898 541,986 50,112 536,814 52,897 601,684
Secondary Sales 2,140 52,648 4,797 229,141 619 22,115
Total Sales of
Electricity 53,038 594,634 54,909 765,955 53,516 623,799
Other 2,034 2,355 1,763
Total Operating Revenues
$55,072 $57,264 $55,279
Primary sales for 1997 were 541,986 MWH, which were approximately 1.0%
higher than primary sales of 536,814 MWH in 1996 and 9.9% lower than sales of
601,684 MWH in 1995. As reflected in the table above, the loss of Houlton Water
Company (HWC), a sales for resale customer, due to a competitive bid effective
January 1, 1996, is the principle reason for the primary sales decrease from
1995 to 1996. In 1995, HWC, the Company's largest customer, represented 11.1%
of consolidated MWH sales and 8.4% of consolidated operating revenues.
MWH sales for resale were 2.9% higher in 1997 than 1996 because of increased
sales to Eastern Maine Electrical Co-op and Perth-Andover Electric Light
Commission. Retail sales were 484,408 MWH in 1997, an increase of 3,552 MWH or
.7% over 1996 sales of 480,856 MWH, primarily due to the re-utilization of the
former Loring AFB by small commercial customers. Compared to 1995, retail sales
increased 1.4% reflecting increased sales to two large industrial customers: J.
Paul Levesque & Sons (a wood products customer) and McCain Foods (a foods
product customer).
During 1996 and 1997, the Company entered into long-term contracts with
five of its largest customers. In exchange for discounts from the Company's
standard rates, these customers agreed to purchase all of their electrical
requirements from the Company through the year 2000. All five of these
customers produced evidence of hardship to continue operations in the area or
were investigating self generation, criteria that the Maine Public Utilities
Commission (MPUC) reviewed before approving these load-retention contracts.
Secondary sales for 1997 of $2,140,000 were $2,657,000 lower than those
sales in 1996 and $1,521,000 higher than sales in 1995. The Company's Maine
Yankee entitlement was sold in 1996 during periods of surplus capacity while in
1997 and 1995 the plant was out of service, as further discussed in the "Maine
Yankee" section of this Annual Report. During the three-year period, the
Company entered into arrangements with other utilities to sell its Wyman Unit
No. 4 and Maine Yankee entitlements, when available, for varying lengths of
time at existing market rates. This energy was replaced, when necessary, with
system purchases, avoiding off-system wheeling costs.
The MPUC has jurisdiction over retail rates. As more fully explained in
the "Regulatory Proceedings - Four-Year Rate Stabilization Plan" section of this
Annual Report, the MPUC approved the four-year rate plan effective January 1,
1996 with increases of 4.4% and 2.9% effective on January 1, 1996 and February
1, 1997, respectively. The four-year rate plan allows for annual increases in
retail rates and eliminated the fuel clause. Prior to the four-year rate plan,
the Company had not sought a base rate increase since November 1, 1992.
(Page 5)
A fuel clause increase of $1.4 million was approved by the MPUC effective April
1, 1995. The Company's customer rates are competitive among investor-owned
utilities in Maine and New England.
The Federal Energy Regulatory Commission (FERC) has jurisdiction over U.S.
wholesale rates, included as sales for resale in the previous table and
discussion.
Energy Supply
The Company's most economical source of supply is hydro energy, which was
80.7% of normal production levels in 1997 and provided 17.1% of the Company's
energy supply. In 1996, hydro production was 126.5% of normal and provided
21.1% of the Company's energy supply. Hydro production in 1995 was 90.8% of
normal and accounted for 18.3% of the Company's total energy supply. The
availability of low cost hydro reduces the need for more expensive sources of
energy. Maine Yankee was out of service for all of 1997 and operated for only
a few weeks in 1995. As more fully explained in the "Maine Yankee" section of
this Annual Report, following an economic analysis, the Maine Yankee Board of
Directors voted on August 6, 1997, to shut down the plant permanently. During
1996, Maine Yankee was restricted to 90% of rated capacity but was able to
provide 31.1% of the Company's total energy supply. In 1995, the nuclear plant
was taken out of service to re-sleeve the steam generator tubes and thus
only contributed 1.5% of the Company's energy supply. To offset the loss of
Maine Yankee production, the Company purchased replacement energy from various
sources, including but not limited to New Brunswick Power, on a competitive
basis. These purchases accounted for 58.9% and 57.5% of the Company's energy
supply in 1997 and 1995 respectively, compared to 30.5% in 1996. The Company's
oil-fired generating facilities provided 4.2% of the Company's energy supply in
1997, compared to 1.2% in 1996 and 3.6% in 1995. In 1986, under an agreement
ordered by the MPUC, the Company began purchasing the output from an 17.6 MW
wood-burning independent power producer, currently owned by Wheelabrator-Sherman
(W-S). As more fully explained in the "Regulatory Proceedings - Restructured
Agreement with Wheelabrator-Sherman" section of this Annual Report, the Company
and W-S have agreed on a new purchase power arrangement. These mandated
purchases from this facility represented 19.8% of the Company's energy supply
in 1997, compared to 16.1% and 19.1% in 1996 and 1995, respectively.
On December 19, 1997, the Company announced the signing of an agreement for
the purchase of power until 2000 from Alternative Energy's Beaver Power Plant
in Ashland, Maine, as a replacement for Maine Yankee energy.
Electric Output By Source (Percent)
1997 1996 1995
Oil 4.2 1.2 3.6
Cogeneration 19.8 16.1 19.1
Purchases 58.9 30.5 57.5
Nuclear - 31.1 1.5
Hydro 17.1 21.1 18.3
Total 100.0 100.0 100.0
Operating Expenses
For the three-year period 1995-1997, purchased power expenses are as
follows:
(Dollars in Thousands)
1997 1996 1995
Wheelabrator-Sherman $15,911 $15,593 $14,507
Maine Yankee 12,303 10,185 7,972
NB Power 10,786 3,498 9,091
System Purchases 1,308 2,544 408
Total Purchased Power 40,308 31,820 31,978
Deferred Fuel (3,699) (1,375) (4,937)
Fuel Expense Write-Off - - 3,500
Net Purchased Power $36,609 $30,445 $30,541
Wheelabrator-Sherman's slight increase in 1997 expenses compared to 1996
was caused by a contractual price increase of 5% partially offset by a 2.7%
decrease in output. For 1997, 1996 and 1995, these mandated purchases from
Wheelabrator-Sherman represented 39.5%, 49.0%, and 45.4%, respectively, of total
purchased power expenses. As more fully explained in the "Maine Yankee" section
of this Annual Report, Maine Yankee was out of service in 1997. The joint
owners of the nuclear plant voted to close the plant permanently in August,
1997. The Company purchased replacement energy primarily from NB Power, an
increase of $7.3 million in 1997 over 1996. As part of a rate stipulation
approved by the Maine Public Utilities Commission on January 30, 1998, the
Company agreed to a 1997 write-off of $1.5 million of deferred capacity charges
related to the 1997 Maine Yankee refueling. The increase in 1997 Maine Yankee
expenses also reflects the efforts to restart the plant in early 1997 before the
owners voted to start decommissioning. System purchases in 1997 decreased by
$1,236,000 compared to 1996, respectively, due to decreased power marketing
activities, as discussed in the "Operating Revenues and Energy Sales" section
of this Annual Report. Deferred fuel expense, a component of purchased power,
was a negative $3,699,000 in 1997, compared to a negative $1,375,000 in 1996 and
a negative $4,937,000 in 1995. Negative deferred fuel indicates expenses
deferred to a period when these costs will be collected in rates. As more fully
discussed in the "Regulatory Proceedings - Four-Year Rate Stabilization Plan"
section of this Annual Report, the fuel clause adjustment was eliminated
effective on January 1, 1996 with the exception of the annual
Wheelabrator-Sherman deferral of fuel expenses of $1.5 million and, in the event
of a Maine Yankee outage exceeding six consecutive months, the Company's Rate
Stabilization Plan provides a sharing mechanism. This provision went into
effect on June 6, 1997, with approximately $2.3 million deferred through the end
of 1997, subject to future collection. As part of the 1995 rate plan, the
Company wrote off $3.5 million, before income taxes, of the replacement power
costs associated with the Maine Yankee outage, which had been deferred under the
previous fuel clause.
(Page 6)
Other operation and maintenance expenses for the three-year period are as
follows:
(Dollars in Thousands)
1997 1996 1995
Generation
Fuel Expense $ 893 $ 387 $ 824
Other 1,321 1,571 2,031
2,214 1,958 2,855
Transmission and
Distribution 3,609 4,228 3,668
Customer Accounting and
General Administrative 6,947 7,629 6,740
Total $12,770 $13,815 $13,263
Fuel expenses for generation increased by $506,000 in 1997 compared to 1996
with the increased generation at Wyman Unit No. 4, an oil-fired generating
facility. Other generation expenses decreased by $250,000 reflecting a decrease
in labor costs at the Company's wholly owned subsidiary's facilities and reduced
expenses at Wyman Unit No. 4. Transmission and distribution expenses decreased
$619,000 in 1997, compared to 1996 reflecting decreased power marketing wheeling
activities and higher than normal tree trimming in 1996. Customer accounting
and general and administrative expenses decreased $682,000 from $7,629,000 in
1996 to $6,947,000 in 1997 due to medical expense savings of $473,000 and
pension costs of $402,000 related to an early retirement program in March 1996.
Maine Yankee
The Company owns 5% of the Common Stock of Maine Yankee, which operated an 860
MW nuclear power plant (the "Plant") in Wiscasset, Maine. On August 6, 1997,
the Board of Directors of Maine Yankee voted to permanently cease power
operations and to begin decommissioning the Plant. The Plant experienced a
number of operational and regulatory problems and has been shut down since
December 6, 1996. The decision to close the Plant permanently was based on
an economic analysis of the costs, risks and uncertainties associated with
operating the Plant compared to those associated with closing and
decommissioning it. The Plant's operating license from the Nuclear Regulatory
Commission (NRC) was due to expire on October 21, 2008.
The Plant generally provided reliable and low-cost power from the time it
commenced operations in late 1972 to 1995. Beginning in early 1995, however,
Maine Yankee encountered various operational and regulatory difficulties with
the Plant. In 1995, the Plant was shut down for almost the entire year to
repair a large number of steam generator tubes that were exhibiting defects.
Shortly before the Plant was to go back on-line in December 1995, a group with
a history of opposing nuclear power released an undated, unsigned, anonymous
letter alleging that in 1988 Yankee Atomic (then an affiliated consultant of
Maine Yankee) and Maine Yankee had used the results of a faulty computer code
as a basis to apply to the NRC for an increase in the Plant's power output. In
response to the allegation, on January 3, 1996, the NRC issued a Confirmatory
Order that restricted the Plant to 90 percent of its licensed thermal operation
level, which restriction was still in effect when the Plant was permanently shut
down.
As a result of the controversy associated with the allegations, the NRC, at
the request of the Governor of Maine, conducted an intensive Independent Safety
Assessment (ISA) of the Plant in the Summer and Fall of 1996. On October 7,
1996, the NRC issued its ISA report, which found that while the Plant had been
operated safely, there were weaknesses that needed to be addressed, which would
require substantial additional spending by Maine Yankee. On December 10, 1996,
Maine Yankee responded to the ISA report, acknowledged many of the weaknesses,
and committed to revising its operations and procedures to address the NRC's
criticisms.
Another result of the controversy associated with the allegations was an
investigation of Maine Yankee initiated by the NRC's Office of Investigations
(OI), which, in turn, referred certain issues to the United States Department
of Justice (DOJ) for possible criminal prosecution. Subsequently, on September
27, 1997, the DOJ, through the United States Attorney for Maine, announced that
its review had revealed no grounds for criminal prosecution. The Company
believes that the OI investigation, however, could ultimately result in the
imposition of civil penalties, including fines, on Maine Yankee.
In 1996, the Plant was generally in operation at the 90-percent level from
late January to early December, except for a two-month outage from mid-July to
mid-September. The Plant was shut down again on December 6, 1996, to address
several concerns, and has not operated since then. The precipitating event
causing the shutdown was the need to evaluate and resolve cable-separation
compliance issues, and on December 18, 1996, the NRC issued a Confirmatory
Action Letter requiring the Plant to remain shut down until Maine Yankee's plan
for resolving the cable-separation issues was accepted by the NRC. Subsequently,
Maine Yankee uncovered additional issues, including among others the possibility
of having to replace defective fuel assemblies, address additional
cable-separation issues, and determine the condition of the Plant's steam
generators, all of which contributed to further operational uncertainty. On
January 29, 1997, the Plant was placed on the NRC's Watch List, and on
January 30, 1997, the NRC issued a supplemental Confirmatory Action Letter
requiring the resolution of additional concerns before the Plant could be
restarted.
In December 1996, Maine Yankee requested proposals from several utilities with
large and successful nuclear programs to provide a management team, and
ultimately contracted with Entergy Nuclear, Inc., effective February 13, 1997,
for management services that included providing a new president and regulatory
compliance officer. The Entergy-provided management team made progress in
addressing technical issues, but a number of operational and regulatory
uncertainties remained. On May 27, 1997, the Board of Directors of Maine Yankee
voted to minimize spending while preserving the options of restarting the Plant
or conveying ownership interests to a third party. After unsuccessful
negotiations with one prospective purchaser, Maine Yankee found no other
interest in purchasing the Plant and, based on its economic analysis, closed the
Plant permanently.
As required by the NRC, on August 7, 1997, Maine Yankee certified to the NRC
that Maine Yankee had permanently ceased operations and that all fuel assemblies
had been permanently removed from the Plant's reactor vessel. On August 27,
1997, Maine Yankee filed the required Post-Shutdown Activities Report with the
NRC, describing its planned post-shutdown activities and a proposed schedule.
(Page 7)
The Company's 5% ownership interest in Maine Yankee's common equity amounted
to $4.0 million as of December 31, 1997, and under Maine Yankee's Power
Contracts and Additional Power Contracts, the Company is responsible for 5% of
the costs of decommissioning the Plant. Maine Yankee's most recent estimate of
the cost of decommissioning is $380.4 million, based on a 1997 study by an
independent engineering consultant, plus estimated costs of interim spent-fuel
storage of $127.6 million, for an estimated total cost of $508 million (in 1997
dollars). The previous estimate for decommissioning, by the same consultant,
was $316.6 million (in 1993 dollars).
On September 1, 1997, Maine Yankee estimated the sum of the future payments
for the closing, decommissioning and recovery of the remaining investment in
Maine Yankee to be approximately $930 million, of which the Company's 5% share
would be approximately $46.5 million. Legislation enacted in Maine in 1997
calling for restructuring the electric utility industry provides for recovery
of decommissioning costs, to the extent allowed by federal regulation, through
the rates charged by the transmission and distribution companies. Based on the
Maine legislation and regulatory precedent established by the FERC in its
opinion relating to the decommissioning of the Yankee Atomic nuclear plant, the
Company believes that it is entitled to recover substantially all of its share
of such costs from its customers and, as of December 31, 1997, is carrying on
its consolidated balance sheet a regulatory asset and a corresponding liability
in the amount of $43.4 million, which is the $46.5 million discussed above net
of the Company's post-September 1, 1997 cost-of-service payments to Maine
Yankee.
On September 2, 1997, the MPUC released the report of a consultant it had
retained to perform a management audit of Maine Yankee for the period January
1, 1994, to June 30, 1997. The report contained both positive and negative
conclusions, the latter including: that Maine Yankee's decision in December 1996
to proceed with the steps necessary to restart the Plant was "imprudent", that
Maine Yankee's May 27, 1997 decision to reduce restart expenses while exploring
a possible sale of the Plant was "inappropriate", based on the consultant's
finding that a more objective and comprehensive competitive analysis at that
time "might have indicated a benefit for restarting" the Plant; and that those
decisions resulted in Maine Yankee incurring $95.9 million in "unreasonable"
costs. The Company has expensed its share of these costs. On October 24, 1997,
the MPUC issued a Notice of Investigation initiating an investigation of the
shutdown decision and of the operation of the Plant prior to shutdown, and
announced that it had directed its consultant to extend its review to include
those areas. The Company does not know how the MPUC plans to use the
consultant's report, but believes the report's negative conclusions are
unfounded and may be contradictory. The Company believes it would have
substantial constitutional and jurisdictional grounds to challenge any effort
in an MPUC proceeding to alter wholesale Maine Yankee rates made effective by
the FERC. On November 7, 1997, Maine Yankee and Central Maine Power initiated
a legal challenge to the MPUC investigation in the Maine Supreme Judicial Court
alleging that such an investigation falls exclusively within the jurisdiction
of the FERC and that the MPUC investigation is therefore barred on
constitutional grounds. The Company joined in this appeal. The MPUC
subsequently stayed its investigation pending the outcome of Maine Yankee's FERC
rate case, while indicating that its consultant would continue its extended
review. The Maine Supreme Court, on motions of the parties, stayed the appeal
pending resolution of the FERC proceeding.
During 1997, the Company incurred Maine Yankee replacement power costs of
approximately $7,302,000, of which $2,324,000 has been deferred under the
Company's rate stabilization plan, and also incurred additional operating costs
of approximately $3.0 million associated with the efforts to restart and
subsequently close Maine Yankee, which have adversely impacted the Company's
earnings.
The February 1, 1998, rate increase, as described in the "Regulatory
Proceedings - Four-Year Rate Stabilization Plan" section of this Annual Report,
included a portion of these recoverable 1997 Maine Yankee replacement power
costs with the remaining costs included in the February 1, 1999 rate increase.
However, the collection of future Maine Yankee replacement power costs will be
subject to the MPUC's previously-mentioned prudence review of the prudency of
closing Maine Yankee.
Earnings and Dividends
For 1997, the loss per share was $1.35 based on a loss of $2,177,137.
Earnings per share in 1996 were $1.31 based on net income available for Common
Stock of $2,110,694. For 1995, earnings per share before and after
extraordinary items were $.57 and a loss of $3.29, respectively. The average
shares outstanding for all three years were 1,617,250.
As discussed in the "Maine Yankee" section of this Annual Report, the plant
did not operate during 1997 and was shut down permanently in August 1997. The
related replacement power and increased capacity expenses reduced earnings by
$2.94 per share compared to 1996. In 1995, extraordinary write-offs of $6.2
million, net of income taxes, or $3.86 per share, to eliminate the Company's
remaining wholesale investment in Seabrook and other wholesale plant were an
element of the four-year rate stabilization plan approved by the Maine Public
Utilities Commission on November 13, 1995. In addition, the implementation of
the rate plan included a charge of $2.1 million, or $1.30 per share, to
operating expenses for previously deferred retail fuel representing the
replacement power expenses incurred during the Maine Yankee resleeving outage
in 1995. Refer to the "Regulatory Proceedings - Four-Year Rate Stabilization
Plan" section of this Annual Report for further discussion.
The Company's return on equity for 1997 was a negative 6.02% compared to 5.48%
for 1996 and a negative 12.33%, after extraordinary items, for 1995.
Your Board of Directors reduced the quarterly dividend from $.46 to $.25 per
share effective for the April 1, 1997 payment. The dividends paid in 1997 were
$1.21 per share and $1.84 per share in both 1996 and 1995. The dividend
reduction, along with other actions to control 1997 construction expenditures
and operating expenses, was required to improve the Company's cash flows in
response to the difficulties at Maine Yankee. For additional information, see
the "Liquidity and Capital Resources" section of this Annual Report.
(Page 8)
Liquidity and Capital Resources
The accompanying "Statements of Consolidated Cash Flows" reflect the Company's
liquidity and financial strength. The statements report the net cash flows
generated from or used for operating, financing, and investing activities.
In 1997, the additional replacement power and capacity expenses to restart and
subsequently to close and start decommissioning Maine Yankee significantly
reduced the Company's earnings and cash flows. As a result, the Company had to
increase short-term borrowing by $5,800,000 to fund operating and construction
activities and pay dividends. The Company also withdrew $2.0 million from
proceeds held in trust from the 1996 tax-exempt bonds, based on qualifying
property additions. As of December 31, 1997, $2.3 million remained in trust to
be withdrawn by June 1999. Net cash flows used in operating activities were
$1.7 million. The Company paid dividends of $1.2 million, made debt payments
of $1.3 million, and invested $2.7 million in electric plant.
In 1996, net cash flows generated from operating activities were $7.4 million.
During 1996, $15 million in tax-exempt bonds were issued with the proceeds used
to refund a $10 million series issued in 1991. The remaining $5 million of
proceeds were deposited with the trustee to be withdrawn based on qualifying
property additions and eligible issuance costs. During 1996, the Company
withdrew $1.1 million from these proceeds, paid dividends of $3 million, made
additional long-term debt payments of $1.3 million and invested $3.4 million
in electric plant. During 1996, the Company did not require any additional
short-term borrowings to meet working capital requirements.
The previously mentioned write-offs required by the rate plan in late 1995,
the impact of the closure of Loring Air Force Base in the Fall of 1994, and the
extended outage required for the resleeving of Maine Yankee all adversely
impacted 1995 earnings, resulting in a loss of $5.3 million. Despite the loss,
net cash flows generated from operating activities were $3.4 million in 1995,
which reflect Maine Yankee replacement power costs of $5.7 million and
resleeving costs of $1.3 million. In 1995, the Company borrowed an additional
$1.4 million utilizing its short-term credit facilities. During 1995, the
Company paid $3 million in dividends, made debt payments of $65,000 and invested
$3.4 million in electric plant.
For additional information regarding construction expenditures for 1995 to
1997 and anticipated construction expenditures for 1998, see Note 10,
"Commitments, Contingencies, and Regulatory Matters - Construction Program", of
the Notes to Consolidated Financial Statements.
The Company uses short-term borrowings to satisfy working capital
requirements. As previously mentioned, in 1997 the Company required additional
short-term borrowings from its credit facilities. The Company ended 1997 with
$7.2 million of notes outstanding under the credit facilities, while $1.4
million was outstanding at the end of both 1996 and 1995. During 1995 to 1997,
required borrowing under the Company's credit facilities were all below the
existing prime rate. For additional information on the short-term credit
facility, see Note 5, "Short-Term Credit Arrangements", of the Notes to
Consolidated Financial Statements.
On June 19, 1996, the Maine Public Utilities Financing Bank (MPUFB) issued $15
million of its tax-exempt bonds due April 1, 2021 (the 1996 Series) on behalf
of the Company. The proceeds of the new 1996 Series were used to refund the $10
million 1991 tax-exempt Series through the payment of a refunding note from
Fleet Bank of Maine and provided $5 million for the acquisition of qualifying
property. Pursuant to the long-term note issued under a loan agreement between
the Company and the MPUFB, the Company has agreed to make payments to the MPUFB
for the principal and interest on the bonds. Concurrently, pursuant to a letter
of credit and reimbursement agreement, the Company caused a Direct Pay Letter
of Credit for an initial term of three years to be issued by the Bank of New
York for the benefit of the holders of such bonds. To secure the Company's
obligations under the letter of credit and reimbursement agreement, the Company
issued a second mortgage bond to the Bank of New York, as Agent, under the
reimbursement agreement, in the amount of $15,875,000. The Company has
the option of selecting weekly, monthly, annual or term interest rate periods
for the 1996 Series. The initial interest period selected by the Company was
weekly, and the initial weekly interest rate was 3.75% per annum. At the end
of 1997, the cumulative effective interest rate since issuance for this series
was 5.705%.
The Company has the ability to finance through the issuance of Common and
Preferred Stock. The Company is authorized to issue up to 3,000,000 shares of
Common Stock. In addition, the Company's restated articles of incorporation
authorize the issuance of $200,000 shares of Preferred Stock with the par value
of $100 per share and 200,000 shares of Preferred Stock with the par value of
$25 per share. The Company can also issue First Mortgage Bonds of $6.5 million
and Second Mortgage Bonds of $24 million without bondable property additions.
In order to maintain the Company's common equity at levels appropriate for an
investor-owned utility, the Company has repurchased 250,000 shares at a cost of
$5,714,376. The original five-year program approved by the Maine Public
Utilities Commission (MPUC) expired in September 1994. On November 1, 1994, the
MPUC approved the Company's application to repurchase up to an additional
300,000 shares over a five-year period. With the write-offs required by the
rate plan and the operating loss in 1997, the Company does not anticipate using
the program to adjust its capital structure.
In early 1997, in anticipation of a lengthy and expensive outage to restart
Maine Yankee, the Company obtained amendments to the short-term revolving credit
agreement and the letter of credit supporting the 1996 revenue bonds. These
amendments, dated March 28, 1997, modified interest coverage tests to exclude
Maine Yankee incremental replacement power costs through September 30, 1997.
Under the amendment to the revolving credit agreement, the Company was obligated
to issue a first mortgage bond of $11 million by May 15, 1997 as collateral for
the maximum amount of its obligations under the agreement. After receiving
approval from the Maine Public Utilities Commission on April 28, 1997, the
Company issued the bonds on May 5, 1997. As discussed in the "Maine Yankee"
section of this Annual Report, the Maine Yankee owners subsequently voted to
close the nuclear power plant and start decommissioning. However, the
previously-mentioned amendments did not cover additional Maine Yankee
replacement and capacity expenses in the fourth quarter of 1997, and the
Company was not able to attain its interest coverage tests.
(Page 9)
The Banks have granted a waiver for these fourth quarter coverage tests. For
1998, the Banks have agreed to amend these interest coverage tests to deal with
these additional Maine Yankee costs. Based on the Company's current
projections, the Company believes that it can attain these amended interest
coverage tests.
The final sinking fund payment for the 7-1/8% Series of First Mortgage Bonds
of $2.9 million will be made during 1998. The Company estimates that additional
short-term borrowings of $2 million will be needed to satisfy the payment.
Based on current projections, the Company estimates that operating cash flows
will be sufficient to cover its other sinking fund payments, construction
activities and other financial obligations.
Employees
At the end of 1997, the Parent Company had 149 full-time employees compared
to 155 for 1996. The Subsidiary had 9 full-time employees for 1997 compared to
10 for 1996. Consolidated payroll costs were $6.5 million for both 1997 and
1996.
Local 1837 of the International Brotherhood of Electrical Workers ratified a
three-year contract with the Parent Company, effective on October 1, 1996. The
agreement included a 2.9% wage increase in the first year and a 2.75% increase
in each of the last two years of the contract.
The Subsidiary and Local 1733 of the International Brotherhood of Electrical
Workers ratified a one-year contract extension effective January 1, 1998. The
new agreement includes a wage increase of 1.93% for the calendar year 1998. The
three-year contract that expired December 31, 1997 allowed annual wage increases
of 3.25%.
Regulatory Proceedings
Industry Restructuring
On May 29, 1997, legislation titled "An Act to Restructure the State's
Electric Industry" was signed into law by the Governor of Maine. The principal
provisions with accounting impact on the Company are as follows:
1. Beginning on March 1, 2000, all consumers of electricity have the right to
purchase generation services directly from competitive electricity
suppliers who will not be subject to rate regulation.
2. By March 1, 2000, the Company, Central Maine Power Company (CMP), and
Bangor Hydro-Electric Company (BHE) must divest themselves of all
generation related assets and business functions except for:
a) contracts with qualifying facilities, such as the Company's power
contract with Wheelabrator-Sherman (W-S), and conservation providers;
b) nuclear assets, namely, the Company's investment in the Maine Yankee
Atomic Power Company;
c) facilities located outside the United States, i.e., the Company's hydro
facility in New Brunswick, Canada: and
d) assets that the MPUC determines necessary for the operation of the
transmission and distribution services.
As required by the electric utility industry restructuring legislation
discussed above, the Company has offered for sale all of its generating
capacity, including its Canadian subsidiary, with a total net book value of
$11.0 million as of December 31, 1997. This plan has been approved by the Maine
Public Utilities Commission, which must also approve the ultimate sale of these
assets. The Company believes it will take at least a full year to complete this
divestiture process, which began in late August, 1997. Bids for the assets were
solicited and collected on January 15, 1998, and negotiations with the
successful bidders are currently underway. The Company cannot predict the final
outcome of the proposed divestiture.
3. The Company, through a regulated affiliate, will continue to provide
transmission and distribution services which will be subject to continued
rate regulation by the MPUC.
4. Maine electric utilities will be permitted a reasonable opportunity to
recover legitimate, verifiable and unmitigable costs that are otherwise
unrecoverable as a result of retail competition in the electric utility
industry (so-called "stranded costs").
The MPUC shall determine these stranded costs by considering:
a) the utility's regulatory assets related to generation, i.e., the
Company's unrecovered Seabrook investment;
b) the difference between net plant investment in generation assets
compared to the market value for those assets; and
c) the difference between future contract payments and the market value of
the purchased power contracts, i.e., the W-S contract.
By July 1, 1999, the MPUC will have estimated the stranded costs or
the Company and the manner for the collection of these costs by the
transmission and distribution company. Customers reducing or eliminating
their consumption of electricity by switching to self-generation,
conversion to alternative fuels or utilizing demand-side management
measures cannot be assessed exit or entry fees.
The Company estimates its stranded costs to be approximately $85
million, based on the completion of the W-S contract restructuring, market
power estimates beyond 2000 and regulatory treatment of the Company's
remaining Seabrook investment, but does not include any benefits from the
Company's sale of generating assets.
5. The MPUC shall include in the rates charged by the transmission and
distribution utility decommissioning expenses for Maine Yankee. In 2003,
and every three years thereafter until the stranded costs are recovered,
the MPUC shall review and adjust the stranded cost recovery amounts and
related transition charges. However, the MPUC may adjust the amounts at
any point in time that they deem appropriate. Since the legislation
provides for our recovery of stranded costs by the transmission and
distribution company, the Company will continue to recognize existing
regulatory assets and plant costs as provided by Emerging Issues Task Force
97-4 "Deregulation of the Pricing of Electricity" (EITF 97-4).
(Page 10)
6. Employees other than officers, displaced as a result of retail competition
will be entitled to certain severance benefits and retraining programs.
These costs will be recovered through charges collected by the regulated
transmission and distribution company.
The MPUC will conduct several rulemaking proceedings associated with the
new restructuring law. The Company is presently reviewing its business
operations and the opportunities that the new restructuring law presents.
In accordance with EITF 97-4 when all of the details of the restructuring
plan are determined by the MPUC rulemaking, the Company will discontinue
application of the Statement of Financial Accounting Standards No. 71 (SFAS 71),
"Accounting for the Effects of Certain Types of Regulations", for the generating
segment of its business jurisdiction. As a result, the Company continues to
defer certain costs as regulatory assets in instances where recovery through
future regulatory cash flows is anticipated.
Four-Year Rate Stabilization Plan
On November 13, 1995, the Maine Public Utilities Commission (MPUC) approved
a stipulation signed by the Company, the Commission Staff, and the Maine Public
Advocate. This stipulation, effective January 1, 1996, established a multi-year
rate plan for the Company that provides our customers with predictable rates
through 1999 and shares operating risks and benefits between the Company's
shareholders and customers.
Under the terms of the stipulation, which applies cost of service principles,
the Company's retail rates were increased by 4.4% and 2.9% on January 1, 1996
and February 1, 1997, respectively. The Company has the right to receive
additional annual increases in retail rates of 2.75% on February 1, 1998 and
February 1, 1999. The Company has agreed that it will seek no other increases,
for either base or fuel rates, except as provided under the terms of the plan.
There will be no fuel clause adjustments for the duration of the plan.
The Company, under the terms of the plan, recognized write-offs in 1995,
totaling approximately $8,340,000, net of income taxes, or approximately $5.16
per share. As a result of the application of SFAS No. 101 "Accounting for the
Discontinuation of Application of FASB Statement No. 71", approximately
$4,846,000, net of income taxes, of the Company's investment in the Seabrook
nuclear project previously allocated to wholesale sales and $1,390,000, net of
income taxes, of other wholesale plant investment and regulatory assets
have been written off and classified as extraordinary items. The remaining
segments of the Company continue to meet the criteria of SFAS No. 71 "Accounting
for the Effects of Certain Types of Regulation". In addition, $2,104,000, net
of income taxes, of deferred retail fuel has been charged to operating expenses.
The Company will also be permitted to defer $1,500,000 annually of the costs
of its purchases from Wheelabrator-Sherman during each of the four years of the
rate plan. The plan permits the Company to recover this deferred amount, up to
a total of $6,000,000, in rates beginning in the year 2001. See "Restructured
Agreement with Wheelabrator-Sherman" below. The rate plan provides for the
deferral, until the year 2000, of approximately $1.3 million, net of income
taxes, of uncollected retail fuel at the beginning of the rate plan, while an
additional $300,000, net of income taxes, will be collected in rates over the
rate plan period.
The increases are subject to adjustments resulting from the operation of a
profit-sharing mechanism, as well as the mandated cost and plant outage
provisions of the plan. The profit-sharing mechanism is based on a target
return on equity of 11%, calculated using certain retail ratemaking
methodologies, and is available for the rate increases in 1998 and 1999. The
profit-sharing mechanism establishes a bandwidth of 300 basis points around the
target return on equity. All gains or losses within that bandwidth will be
borne entirely by the Company's shareholders. Any earnings above or below the
bandwidth will be shared 50/50 by shareholders and customers. Moreover, the
Company is allowed to terminate the rate plan and file for a general rate
increase if its earnings fall 500 or more basis points below the target return
on equity during any twelve-month period during the term of the plan.
The plan also provides that if either Maine Yankee or Wheelabrator-Sherman
ceases operation for more than six months, the Company will be permitted to
adjust its allowed rate increases by half of the net costs or net savings
resulting from an outage. Any net costs or net savings realized during the
first six months of the outage would accrue entirely to shareholders. The
Company is also permitted to adjust the annual increases because of certain
mandated costs, such as tax or accounting changes, if any such change affects
the Company's annual revenue requirements by more than $300,000. The Company's
success under the rate plan was dependent on normal operation of Maine Yankee.
As discussed in the "Maine Yankee" section of this Annual Report, Maine Yankee
owners voted to close the plant in August of 1997 and the additional expenses
associated with restarting and subsequently the efforts to close the plant
materially reduced the Company's earnings and cash flows. As previously
mentioned, the MPUC is awaiting the FERC's decision on Maine Yankee's FERC rate
case before addressing issues regarding the prudency of closing the nuclear
power plant. With these uncertainties concerning Maine Yankee, the Company
negotiated with the MPUC staff and the Public Advocate to modify the rate plan
to deal with these Maine Yankee costs and issues to assure reasonable rates for
our customers and reasonable returns to our stockholders.
On January 26, 1998, the MPUC approved a 3.9% February 1, 1998 rate increase,
according to terms of a stipulation agreed to by the Company and the Public
Advocate, with the support of the MPUC staff. The principal elements of the
agreement are as follows:
1. The rate increase effective February 1, 1998 was 3.9%, consisting of the
specified increase of 2.75% and approximately $562,000 of the 1997
recoverable Maine Yankee replacement power costs (1.15%);
2. The minimum rate increase effective February 1, 1999 will be 3.1%,
consisting of a specified increase of 2.0% and the remaining recoverable
1997 Maine Yankee replacement power costs of $523,000;
3. Maine Yankee replacement power costs for the period October 1, 1997
through September 30, 1998 will be offset by the 1998 savings under the
restructured Wheelabrator-Sherman contract (See "Restructured Agreement
with Wheelabrator-Sherman", below) with the recovery of any incremental
Maine Yankee replacement power costs subject to a final order by the
MPUC in its review of the prudency of closing Maine Yankee;
(Page 11)
4. The Company wrote off unamortized Maine Yankee refueling outage costs
of approximately $1,458,000 in 1997;
5. The Company waives its right to collect additional revenues for the
profit-sharing review period, i.e. the twelve months ended September 30,
1997, since the earnings deficiency was the result of the closing of
Maine Yankee and, based on the 3.9% increase granted by the MPUC, the
Company expects to earn a reasonable rate of return in 1998 without
these additional revenues;
6. Maine Yankee replacement power costs for the period October 1, 1998
through February 29, 2000 will be deferred for subsequent recovery in
retail rates, subject to the MPUC's final order on its prudency review.
With the resolution of the uncertainties regarding the near-term recovery of
Maine Yankee replacement power costs, the Company has negotiated amendments to
the Company's revolving credit agreement and letter of credit and reimbursement
agreement supporting the tax-exempt bond issue to avoid violation of interest
coverage tests. The Company believes that its rate plan deals effectively with
the closing of Maine Yankee, with customers and shareholders sharing the burden
equally. However, the Company cannot predict what the MPUC's decisions will be
concerning the prudency of closing Maine Yankee. If the Company is adversely
impacted by the MPUC prudency decision, or if the Company is unable to complete
the financing for the restructured Wheelabrator-Sherman contract, the Company
may be required to seek an emergency rate increase and will review all cash
expenditures, including the level of dividends.
Restructured Agreement with Wheelabrator-Sherman
The Company has been attempting for several years to restructure the terms of
its current Power Purchase Agreement (PPA) with Wheelabrator-Sherman (W-S). The
Company was ordered into the PPA by the MPUC in 1986, which required the
purchase of the entire output (up to 126,582 MWH) of a 17.6 MW biomass plant
trough December 31, 2000. Under the earlier agreement, either party could renew
the agreement for an additional fifteen years at prices to be determined by
mutual agreement, or absent mutual agreement, by the MPUC. By agreement dated
October 15, 1997, the Company and W-S have finally amended the PPA.
Under the terms of this amendment, W-S agreed to reductions in the price of
purchased power of approximately $10 million over the PPA's current term in
exchange for an up-front payment of $8.7 million. The Company and W-S also
agreed to renew the PPA for an additional six years at agreed-upon prices. The
Company believes the amended PPA will help relieve the financial pressure caused
by the recent closure of Maine Yankee as well as the need for substantial
increases in its retail rates, and is, therefore, in the best interests of the
Company, its customers, and shareholders.
The Company intends to finance the up-front payment to W-S from funds obtained
from the Finance Authority of Maine (FAME). Absent FAME financing, the Company
does not believe it could obtain the funds on terms sufficiently economic to
justify the arrangement with W-S. In its filing with MPUC, the Company further
asked the MPUC for a determination that any so-called stranded cost created by
the amended PPA will be recoverable from customers to the extent permitted by
Maine law.
On December 22, 1997, the MPUC approved the amended purchase power agreement
and determined that the up-front costs created by the amended PPA will be
treated as stranded cost and, therefore, recovered in rates of the transmission
and distribution company. On February 19, 1998, the Board of Directors of FAME
authorized the issuance and sale of securities under FAME's electric rate
stabilization program. The Company expects to complete the financing during the
second quarter of 1998.
Open Access Transmission Tariff
On March 31, 1995, the Company filed an open access transmission tariff with
the Federal Energy Regulatory Commission (FERC). This tariff provides fees for
various types and levels of transmission and transmission-related services that
are required by transmission customers. The tariff, as filed, substantially
increases some of the fees for transmission services and provides separate fees
for various transmission-related services. On May 31, 1995, the FERC approved
the filed tariff, subject to refund. The filing has been vigorously contested
by the Company's wholesale customers. In April, 1996, the FERC issued Order
888, a final rule on open transmission access and stranded cost recovery. As
a result, the Company refiled its tariff on July 9, 1996 to comply with the
Order. Utilities are required to file tariffs under which they would provide
transmission services, comparable to that which they provide themselves, to
third parties on a non-discriminatory basis. A decision by the FERC is not
expected until later in 1998. The Company cannot predict FERC's ultimate
decision in this matter. The Company has not recognized approximately $902,000
collected from our transmission customers under the temporary tariff, since the
rates are subject to refund. Upon final FERC approval of the open access
transmission tariff, the Company will recognize the allowable portion of the
revenues and refund the remainder to our transmission customers.
Year 2000 Issues
The Year 2000 issue is the result of computer programs being written using two
digits rather than four to define the applicable year. Computer programs that
have date-sensitive software using two digits would recognize a date using "00"
as the year 1900 rather than the year 2000, resulting in system failure or
miscalculations. The Company will be replacing the one major software
application containing the problem in response to the industry restructuring
prior to 2000. The Company has reviewed other internal and external interfaces,
including its Banks, and determined no further modifications are necessary and
that a material impact on the Company's financial position or results of
operation is not likely.
(Page 12)
Forward-Looking Statements
The above discussion may contain "forward-looking statements", as defined in
the Private Securities Litigation Reform Act of 1995, related to expected future
performance or our plans and objectives. Actual results could potentially
differ materially from these statements. Therefore, there can be no assurance
that actual results will not materially differ from expectations.
Factors that could cause actual results to differ materially from our
projections include, among other matters, electric utility restructuring; future
economic conditions; changes in tax rates, interest rates or rates of inflation;
and developments in our legislative, regulatory, and competitive environment.
Shareholder Information
General
The Company's Common Stock is listed and traded on the American Stock
Exchange. As of December 31, 1997 and 1996, Common Stock shares issued and
outstanding were 1,617,250. As of December 31, 1997, shares were held by 1,436
shareholders or nominees in forty-nine states, the District of Columbia, Canada,
Poland, and the United Kingdom.
The annual meeting of shareholders is held each year on the second Tuesday
in May at the Company's headquarters in Presque Isle. Market price and dividend
information relative to the two most recent calendar years are shown in the
tabulation below.
Income Tax Status of 1997 Dividends
The Company has determined that the Common Stock dividends paid in 1997 are
fully taxable for federal income tax purposes. These determinations are subject
to review by the Internal Revenue Service, and shareholders will be notified of
any significant changes.
Market Dividends Dividends
Price Paid Declared
High Low Per Share Per Share
1997
First Quarter $18-3/8 $14-1/8 $ .46 $ .25
Second Quarter $14-3/4 $11-3/8 .25 .25
Third Quarter $12-7/8 $10-3/16 .25 .25
Fourth Quarter $12-13/16 $11-3/8 .25 .25
Total Dividends $1.21 $1.00
1996
First Quarter $22-3/8 $19 $ .46 $ .46
Second Quarter $20-3/8 $16-7/8 .46 .46
Third Quarter $19-1/8 $17-3/8 .46 .46
Fourth Quarter $19-1/2 $17-1/8 .46 .46
Total Dividends $1.84 $1.84
Dividends declared within the quarter are paid on the first day of the
succeeding quarter.
(Page 13)
Five-Year Summary of Selected Financial Data
1997 1996 1995 1994 1993
Operating Revenues
$55,072,196 $57,264,165 $55,278,726 $58,368,085 $60,476,212
Income (Loss) Before Extraordinary Items
$(2,177,137) $ 2,110,694 $ 920,500 $ 4,845,647 $ 5,300,840
Extraordinary Items, Net of Taxes
- - (6,235,812) - -
Net Income (Loss) Available for Common Stock
$(2,177,137) $ 2,110,694 $(5,315,312) $ 4,845,647 $ 5,300,840
Basic Earnings (Loss) Per Share of Common Stock
Income (Loss) Before Extraordinary Items
$(1.35) $1.31 $0.57 $2.99 $3.19
Extraordinary Items
- - (3.86) - -
Net Income (Loss)
$(1.35) $1.31 $(3.29) $2.99 $3.19
Dividends Per Share of Common Stock:
Declared Basis
$1.00 $1.84 $1.84 $1.84 $1.78
Paid Basis
$1.21 $1.84 $ 1.84 $ 1.84 $1.76
Total Assets
$163,480,739 $116,714,374 $114,074,091 $122,375,442 $124,936,558
Long-Term Debt Outstanding
$39,805,000 $41,120,000 $37,435,000 $37,500,000 $39,365,000
Less amount due within one year
4,155,000 1,315,000 1,315,000 65,000 1,865,000
Long-Term Debt
$35,650,000 $39,805,000 $36,120,000 $37,435,000 $37,500,000
(Page 14)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Statements of Consolidated Operations Year Ended December 31,
1997 1996 1995
Operating Revenues $55,072,196 $57,264,165 $55,278,726
Operating Expenses
Purchased Power 36,608,989 30,444,691 30,541,496
Other Operation and Maintenance 12,769,987 13,814,768 13,262,894
Depreciation 2,497,364 2,447,585 2,438,528
Amortization 1,641,819 1,649,871 1,838,966
Taxes Other Than Income 1,618,208 1,664,685 1,653,228
Provision (Benefit) for
Income Taxes (975,093) 1,954,747 1,179,336
Total Operating Expenses 54,161,274 51,976,347 50,914,448
Operating Income 910,922 5,287,818 4,364,278
Other Income (Deductions)
Equity in Income of
Associated Companies 477,426 350,008 360,684
Allowance for Equity Funds Used
During Construction 18,964 7,120 3,667
Provision for Income Taxes (61,183) (103,681) (73,269)
Other - Net 59,866 95,678 27,172
Total 495,073 349,125 318,254
Income Before Interest Charges
and Extraordinary Items 1,405,995 5,636,943 4,682,532
Interest Charges
Long-Term Debt and Notes Payable 3,592,474 3,529,867 3,763,395
Less Allowance for Borrowed Funds
Used During Construction (9,342) (3,618) (1,363)
Total 3,583,132 3,526,249 3,762,032
Income (Loss) Before
Extraordinary Items (2,177,137) 2,110,694 920,500
Extraordinary Items, Net of
Taxes of $1,917,399 - - (6,235,812)
Net Income (Loss) Available for
Common Stock $(2,177,137) $2,110,694 $(5,315,312)
Basic Earnings (Loss) Per Share of Common Stock
Income (Loss) Before
Extraordinary Items $(1.35) $1.31 $.57
Extraordinary Items - - (3.86)
Net Income (Loss) $(1.35) $1.31 $(3.29)
Average Shares Outstanding 1,617,250 1,617,250 1,617,250
See Notes to Consolidated Financial Statements.
(Page 15)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Statements of Consolidated Cash Flows Year Ended December 31,
1997 1996 1995
Cash Flow From Operating Activities
Net Income (Loss) $(2,177,137) $2,110,694 $(5,315,312)
Adjustments to Reconcile Net Income (Loss) to
Net Cash Provided by Operations:
Depreciation 2,497,364 2,447,585 2,438,528
Amortization 1,677,399 1,649,871 1,838,966
Extraordinary Items, After
Income Taxes - - 6,235,812
Deferred Income Taxes - Net 812,897 (377,355) 1,165,623
Deferred Investment Tax Credits (72,267) (74,662) (77,027)
Allowance for Funds Used
During Construction (28,306) (10,738) (5,030)
Income on Tax-Exempt Bonds-
Restricted Funds (159,114) (118,443) -
Change in Deferred Regulatory
and Debt Issuance Costs (2,304,765) (267,768) (4,795,603)
Change in Deferred Revenues 272,716 275,846 353,653
Change in Benefit Obligations 546,080 874,267 301,164
Change in Current Assets and Liabilities:
Accounts Receivable and
Unbilled Revenue (800,549) 1,023,602 (246,124)
Deferred Fuel and Purchased
Energy Cost (562,000) - 442,416
Other Current Assets (1,266,582) (366,995) 39,540
Accounts Payable 396,259 244,157 1,150,497
Accrued Taxes and Interest (82,632) (161,894) 11,374
Other Current Liabilities (19,530) (16,673) 4,291
Other - Net (448,950) 153,205 (115,579)
Net Cash Flow Provided By (Used For)
Operating Activities (1,719,117) 7,384,699 3,427,189
Cash Flow From Financing Activities
Dividend Payments (1,212,938) (2,975,740) (2,975,740)
Tax-Exempt Bond Issuance Costs - (398,585) -
Issuance of Tax-Exempt Bonds - 15,000,000 -
Drawdown of Tax-Exempt Bond
Proceeds 1,950,692 1,063,969 -
Retirements of Long-Term Debt (1,315,000)(11,315,000) (65,000)
Short-Term Borrowings, Net 5,800,000 - 1,400,000
Net Cash Flow Provided By (Used In)
Financing Activities 5,222,754 1,374,644 (1,640,740)
Cash Flow Used In Investing Activities
Investment in Restricted Funds - (5,000,000) -
Investment in Electric Plant (2,723,828) (3,444,515) (3,428,784)
Net Cash Flow Used In Investing
Activities (2,723,828) (8,444,515) (3,428,784)
Increase (Decrease) in Cash and
Cash Equivalents 779,809 314,828 (1,642,335)
Cash and Cash Equivalents at
Beginning of Year 1,290,911 976,083 2,618,418
Cash and Cash Equivalents at End
of Year $2,070,720 $1,290,911 $ 976,083
Supplemental Disclosure of Cash Flow Information:
Cash Paid During The Year For:
Interest $3,360,855 $3,536,812 $3,499,198
Income Taxes (1997 is net
of tax refunds of $577,000) $(370,709) $2,939,776 $ 235,076
See Notes to Consolidated Financial Statements.
(Page 16)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Consolidated Balance Sheets
December 31,
Assets 1997 1996
Utility Plant
Electric Plant in Service $96,395,964 $94,969,297
Less Accumulated Depreciation 47,230,455 45,415,398
Net Electric Plant in Service 49,165,509 49,553,899
Construction Work-In-Progress 699,232 461,435
Total 49,864,741 50,015,334
Investments in Associated Companies 4,128,804 3,658,627
Net Utility Plant and Investments in
Associated Companies 53,993,545 53,673,961
Current Assets:
Cash and Cash Equivalents 2,070,720 1,290,911
Deposits for Interest and Dividends 64,024 805,512
Accounts Receivable (less allowance for
uncollectible accounts in 1997,
$215,000 and 1996, $207,028) 5,787,770 5,020,921
Unbilled Revenue 1,686,420 1,652,720
Deferred Fuel and Purchased
Energy Costs 687,000 125,000
Current Deferred Income Taxes - 221,578
Inventory 1,230,922 1,194,222
Income Tax Refund Receivable 1,965,852 713,389
Prepayments 223,333 245,914
Total 13,716,041 11,270,167
Other Assets
Uncollected Maine Yankee
Decommissioning Costs 43,429,478 -
Recoverable Seabrook Costs
(less accumulated amortization and
write-off in 1997, $26,888,235; in 1996,
$25,464,603) 26,298,775 27,722,407
Regulatory Assets-SFAS 109 & 106 13,606,672 12,713,312
Restricted Investments (at cost,
which approximates market) 2,262,896 4,054,474
Deferred Fuel and Purchased
Energy Costs 7,135,137 3,950,512
Unamortized Debt Expense (less
accumulated amortization in 1997,
$579,513 ; in 1996, $386,573) 799,246 936,376
Deferred Regulatory Costs (less
accumulated amortization in 1997,
$1,132,024; in 1996, $1,222,948) 1,013,875 1,756,605
Miscellaneous 1,225,074 1,114,752
Total 95,771,153 52,248,438
Total Assets $163,480,739 $117,192,566
See Notes to Consolidated Financial Statements.
(Page 17)
Capitalization and Liabilities
December 31,
1997 1996
Capitalization (see accompanying statements):
Common Shareholders' Equity $34,297,362 $ 38,091,749
Long-Term Debt 35,650,000 39,805,000
Total 69,947,362 77,896,749
Current Liabilities:
Long-Term Debt Due Within One Year 4,155,000 1,315,000
Notes Payable to Banks 7,200,000 1,400,000
Accounts Payable 4,279,331 3,026,567
Accounts Payable - Associated Companies 623,821 1,182,394
Accrued Employee Benefits 968,079 1,266,011
Deferred Income Taxes Related to Deferred
Fuel Costs 6,493 -
Dividends Declared 404,313 743,936
Customer Deposits 42,617 62,147
Taxes Accrued 77,448 135,759
Interest Accrued 802,363 826,684
Total 18,559,465 9,958,498
Deferred Credits:
Deferred Revenues 902,215 629,499
Uncollected Maine Yankee
Decommissioning Costs 43,429,478 -
Income Taxes 25,722,328 24,172,421
Investment Tax Credits 648,206 720,473
Miscellaneous 4,271,685 3,814,926
Total 74,973,912 29,337,319
Commitments, Contingencies, and Regulatory Matters (Note 10)
Total Capitalization and Liabilities $163,480,739 $117,192,566
(Page 18)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Statement of Consolidated Common Shareholders' Equity
Par Value Paid-In Retained Treasury
Shares Issued Capital Earnings Stock
Balance, January 1, 1995
1,617,250 $13,070,750 $38,317 $39,853,156 $(5,714,376)
Net Loss (5,315,312)
Dividends:
Common Stock ($1.84 per share) (2,975,740)
Balance, December 31, 1995
1,617,250 13,070,750 38,317 31,562,104 (5,714,376)
Net Income 2,110,694
Dividends:
Common Stock ($1.84 per share) (2,975,740)
Balance, December 31, 1996
1,617,250 13,070,750 38,317 30,697,058 (5,714,376)
Net Loss (2,177,137)
Dividends:
Common Stock ($1.00 per share) (1,617,250)
Balance, December 31, 1997
1,617,250 $13,070,750 $38,317 $26,902,671 $(5,714,376)
See Notes to Consolidated Financial Statements.
(Page 19)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Consolidated Statements of Capitalization
December 31,
1997 1996
Common Shareholders' Equity
Common Stock, $7 Par Value-Authorized
3,000,000 Shares in 1997 and 1996;
Issued 1,867,250 Shares in 1997 and 1996 $13,070,750 $13,070,750
Paid-In-Capital 38,317 38,317
Retained Earnings 26,902,671 30,697,058
Total 40,011,738 43,806,125
Treasury Stock-Total Shares of 250,000
in 1997 and 1996, at cost (5,714,376) (5,714,376)
Total $34,297,362 $38,091,749
Long-Term Debt
First Mortgage and Collateral Trust Bonds:
7-1/8% Due Serially through 1998-Interest
Payable, May 1 and November 1 * $ 2,880,000 $ 2,920,000
7.95% Due Serially through 2003-Interest
Payable, March 1 and September 1 * 1,925,000 1,950,000
9.775% Due Serially through 2011-Interest
Payable, March 1 and September 1 * 15,000,000 15,000,000
Second Mortgage and Collateral Trust Bonds:
9.6% Due Serially through 2001-Interest
Payable, March 1 and September 1 * 5,000,000 6,250,000
Public Utility Refunding Revenue Bonds-
Series 1996: Due 2021-Variable Interest
Payable Monthly (4.05% as of
December 31, 1997) 15,000,000 15,000,000
Total Outstanding 39,805,000 41,120,000
Less-Amount Due Within One Year 4,155,000 1,315,000
Total $35,650,000 $39,805,000
Current Maturities and Redemption Requirements for the Succeeding Five Years Are
as Follows:
Long-Term Debt:
1998 $ 4,155,000
1999 $ 1,275,000
2000 $ 1,275,000
2001 $ 2,635,000
2002 $ 2,635,000
Thereafter $27,830,000
* Subject to early redemption premiums as defined in the bond indentures.
See Notes to Consolidated Financial Statements.
(Page 20)
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Regulations
Maine Public Service Company (the Company) is subject to the regulatory
authority of the Maine Public Utilities Commission (MPUC) and, with respect to
wholesale rates, the Federal Energy Regulatory Commission (FERC). As a result
of the ratemaking process, the applications of accounting principles by the
Company differ in certain respects from applications by non-regulated
businesses.
Consolidation and Basis of Presentation
The accompanying consolidated financial statements include the accounts of
the Company and its wholly-owned Canadian subsidiary, Maine and New Brunswick
Electrical Power Company, Limited (the Subsidiary). All intercompany balances
and transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Foreign Currency Translation
The functional currency of the Subsidiary is the U.S. dollar. Accordingly,
translation gains and losses are included in other income. Income and expenses
of the Subsidiary are translated at rates of exchange prevailing at the time the
income is earned or the expenses are incurred, except for depreciation which is
translated at rates existing on the applicable in-service dates. Assets and
liabilities are translated at year-end exchange rates, except for utility plant
which is translated at rates existing on the applicable in-service dates.
Deferred Fuel and Purchased Energy Costs
Prior to 1996, electric rates included adjustment clauses for fuel and
purchased energy costs, through which costs above or below base rate levels are
recoverable from or refundable to customers. Fluctuations between current base
rates and actual costs are deferred until recovered or refunded through
subsequent adjustment clauses, in order to properly match costs with the related
revenues. With the exception of Wheelabrator-Sherman fuel costs and the sharing
provisions for Maine Yankee replacement power, the adjustment clauses have been
discontinued under the terms of the 4-year rate plan beginning in 1996.
Revenue Recognition
Operating revenues include sales billed on a cycle billing basis and
estimated unbilled revenues for electric service rendered prior to the normal
billing cycle.
On May 31, 1995, the FERC approved a temporary wheeling tariff in the
Company's open access transmission filing. The Company has not recognized the
additional revenues of $902,000 from the temporary tariff, since the increase
in the rates charged to our transmission customers are subject to refund. The
Company will recognize these deferred revenues, after any adjustment for
refunds, when the FERC approves a final tariff in the open access transmission
tariff filing.
Utility Plant
Utility Plant is stated at original cost of contracted services, direct
labor and materials, as well as related indirect construction costs including
general engineering, supervision, and similar overhead items and allowances for
the cost of equity and borrowed funds used during construction (AFUDC). The
cost of utility plant which is retired, including the cost of removal less
salvage, is charged to accumulated depreciation. The cost of maintenance and
repairs, including replacement of minor items of property, are charged to
maintenance expense as incurred. The Company's property, with minor exceptions,
is subject to First and Second Mortgage liens.
Costs which are disallowed or are expected to be disallowed for recovery
through rates are charged to income at the time such disallowance is probable.
As further explained in Note 10, "Commitments, Contingencies, and Regulatory
Matters", certain utility plant previously allocated for ratemaking to the
wholesale customers was written off during 1995, resulting in an extraordinary
loss.
Depreciation and Amortization
Utility plant depreciation is provided on composite bases using the
straight-line method. The composite depreciation rate, expressed as a
percentage of average depreciable plant in service, was approximately 3.01%,
2.99%, and 2.96% for 1997, 1996, and 1995, respectively.
Bond issuance costs and premiums paid upon early retirements are amortized
over the terms of the related debt. Recoverable Seabrook costs an deferred
regulatory expenses are amortized over the period allowed by regulatory
authorities in the related rate orders. Recoverable Seabrook costs are being
amortized principally over thirty years (Note 10). Costs associated with
relicensing hydro facilities are amortized over the thirty-year license period.
Income Taxes
Statement of Financial Accounting Standards No. 109 (SFAS 109), "Accounting for
Income Taxes", requires an asset and liability approach to accounting and
reporting income taxes. SFAS No. 109 prohibits net-of-tax accounting and
requires the establishment of deferred taxes on all differences between the tax
basis of assets or liabilities and their basis for financial reporting.
The Company has deferred investment tax credits and amortizes the credits
over the remaining estimated useful life of the related utility plant.
The Company records regulatory assets or liabilities related to certain
deferred tax liabilities or assets, representing its expectation that,
consistent with current and expected ratemaking, those taxes will be recovered
from or returned to customers through future rates.
Investments in Associated Companies
The Company records its investments in Associated Companies (see Note 3)
using the equity method.
Pledged Assets
The Common Stock of the Subsidiary is pledged as additional collateral for
the First and Second Mortgage and collateral trust bonds of the Company.
Inventory
Inventory is stated at average cost.
(Page 21)
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, the Company considers all
highly liquid securities with a maturity, when purchased, of three months or
less to be cash equivalents.
Accounting Pronouncements
In February, 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per
Share". The Company adopted SFAS No. 128 in 1997 with no material impact to
financial reporting, financial position, or results of operations. During 1997,
the FASB issued SFAS No. 130, "Reporting Comprehensive Income", SFAS No. 131,
"Disclosure about Segments of an Enterprise and Related Information", and SFAS
No. 132, "Employees' Disclosures about Pensions and Other Postretirement
Benefits". The adoption of these statements will have no material impact to the
Company's existing financial reporting, financial position, or results of
operations.
Reclassifications
Certain reclassifications have been made to the 1996 and 1995 financial
statements in order to conform to the 1997 presentation.
2. INCOME TAXES
A summary of Federal, Canadian and State income taxes charged (credited) to
income is presented below. For accounting and ratemaking purposes, income tax
provisions included in "Operating Expenses" reflect taxes applicable to revenues
and expenses allowable for ratemaking purposes. The impact of the extraordinary
write-offs described in Note 10, "Commitments, Contingencies, and Regulatory
Matters" is highlighted in the table below. The tax effect of items not
included in rate base are allocated as "Other Income (Deductions)".
1997 1996 1995
Current income taxes $(1,654,540) $2,510,445 $164,009
Deferred income taxes 812,897 (377,355) (687,190)
Investment credits, net (72,267) (74,662) (141,613)
Total income taxes $(913,910) $2,058,428 $(664,794)
Allocated to:
Operating income $(975,093) $1,954,747 $1,179,336
Other income 61,183 103,681 73,269
Extraordinary Items - - (1,917,399)
Total $(913,910) $2,058,428 $(664,794)
The effective income tax rates differ from the U.S. statutory rate as follows:
1997 1996 1995
Statutory rate (34.0)% 34.0% (34.0)%
Excess Canadian taxes 3.3 4.2 1.6
Amortization of recoverable
Seabrook costs 9.1 6.7 5.5
State income taxes (5.9) 5.4 (1.7)
Seabrook wholesale write-off - - 16.7
Other (2.1) (.9) .8
Effective rate (29.6)% 49.4% (11.1)%
The elements of deferred income tax expense (credit) are as follows:
(Dollars in Thousands) 1997 1996 1995
Temporary Differences at Statutory Rates:
Seabrook - costs $ (200) $ (200) $ (234)
Liberalized depreciation 80 166 219
AFUDC-borrowed funds (38) (52) (63)
Deferred fuel 1,479 559 582
Deferred regulatory expense (266) (345) 829
Unbilled and deferred revenue (108) (110) (141)
Accrued pension and postretirement
benefits (182) (414) 40
Other 48 19 (66)
Total temporary differences - operations 813 (377) 1,166
Extraordinary Items - - (1,853)
Total temporary differences -
statutory rates $ 813 $ (377) $ (687)
(Page 22)
The Company has not accrued U.S. income taxes on the undistributed earnings
of the Subsidiary, as the withholding taxes due on the distribution of any
remaining amount would be principally offset by foreign tax credits. No
dividends were received from the Subsidiary in 1997 and 1995, while dividends
were $736,492 in 1996. In 1996, earnings from the Subsidiary exceeded the
dividend by $8,608.
The following summarizes accumulated deferred income taxes established on
temporary differences under SFAS 109 as of December 31, 1997 and 1996.
(Dollars in Thousands)
1997 1996
Seabrook $14,489 $15,273
Property 9,565 8,104
Regulatory expenses 1,540 1,201
Deferred fuel 1,631 978
Pension and post-
retirement benefits (847) (670)
Other (656) (714)
Net accumulated deferred
income taxes $25,722 $24,172
3. INVESTMENTS IN ASSOCIATED COMPANIES
The Company owns 5% of the Common Stock of Maine Yankee Atomic Power Company
(Maine Yankee), a jointly-owned nuclear electric power company, and 7.49% of the
Common Stock of the Maine Electric Power Company (MEPCO), a jointly-owned
electric transmission company. For additional information, see Note 10,
"Commitments, Contingencies, and Regulatory Matters - Capacity Arrangements"
regarding the closing of Maine Yankee.
Dividends received during 1997, 1996, and 1995 from Maine Yankee were
approximately $75,000, $333,750, and $172,500, respectively, and from MEPCO
approximately $7,600 in each year. Substantially all earnings of Maine Yankee
and MEPCO are distributed to investor companies. Condensed financial
information (unaudited) for Maine Yankee and MEPCO is as follows:
(Dollars in Thousands)
Maine Yankee MEPCO
1997 1996 1995 1997 1996 1995
Earnings
Operating revenues
$238,586 $185,661 $205,977 $25,123 $55,391 $49,699
Earnings applicable to
Common Stock
$7,613 $6,640 $7,060 $1,463 $220 $105
Company's equity share
of net earnings
$381 $332 $353 $110 $16 $8
Investment
Total assets
$1,368,143 $602,061 $580,958 $4,362 $10,727 $6,025
Less:
Preferred stock
17,400 18,000 18,600 - - -
Long-term debt
76,665 83,332 89,999 420 620 -
Other liabilities
and deferred credits
1,195,128 429,392 401,158 1,578 9,110 5,147
Net assets $78,950 $71,337 $71,201 $2,364 $997 $878
Company's equity in
net assets $3,948 $3,567 $3,560 $177 $75 $66
(Page 23)
4. INVESTMENT IN JOINTLY-OWNED UTILITY PLANT
The Company has a 3.3455% ownership interest in a jointly-owned utility
plant, W. F. Wyman Unit No. 4 (Wyman), an oil-fired generation plant. The
Company's proportionate share of the direct expenses of Wyman are included in
the corresponding operating expenses in the statements of consolidated
operations. The Company's share in the plant at December 31, 1997 and 1996 is
as follows:
(Dollars in Thousands)
1997 1996
Electric plant in service $6,976 $5,924
Accumulated depreciation (4,450) (3,231)
Net electric plant in service $2,526 $2,693
5. SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit arrangement with two banks. The
revolving credit agreement provides for borrowings up to $10 million through
October 1998 and is subject to extension with the consent of all participating
banks. The Company can utilize, at its discretion, two types of loan options:
A Loans, which are provided on a pro rata basis in accordance with each
participating bank's share of the commitment amount, and B Loans, which
are provided as arranged between the Company and each of the participating
banks. The A Loans, at the Company's option, bear interest equal to either the
agent bank's prime rate or LIBOR-based pricing. The Company also pays a
quarterly commitment fee of .375% of the unused portion of the A Loans. The B
Loans bear interest as arranged between the Company and the participating bank.
As of December 31, 1997, A Loans totalling $7.2 million were outstanding under
this arrangement at 6.5%. As of December 31, 1996, a B Loan for $1.4
million was outstanding at 5.5625%.
The Subsidiary has a $200,000 (Canadian) bank line of credit agreement
providing for interest at the bank's prime rate. There were no borrowings under
this arrangement during 1997.
6. BENEFIT PLANS
U.S. Defined Benefit Pension Plan
The Company has an insured non-contributory defined benefit pension plan
covering substantially all employees. Benefits under the plan are based on
employees' years of service and compensation prior to retirement.
The Company's policy has been to fund pension costs accrued. For the 1997,
1996, and 1995 plan years, the Company has made contributions of $305,000 in
1998, $282,000 in 1997, and $284,000 in 1996, respectively. The periodic
pension cost is comprised of the components listed below as determined using the
projected unit credit actuarial cost method. For 1995 and 1996, the Company
implemented reduction in force programs. In 1995, these early retirement
benefits were deferred and will be amortized over five years in accordance
with the rate plan, while for 1996, the increased pension liability was
expensed.
The components of the net pension cost for 1997, 1996, and 1995 are as
follows:
(Dollars in Thousands)
1997 1996 1995
Service costs for benefits
earned during the period $ 323 $ 298 $ 264
Interest cost on projected
benefit obligation 964 939 932
Return on plan assets:
Actual (2,645) (1,251) (2,021)
Deferred 1,662 298 1,111
Total (983) (953) (910)
Net amortization
and deferral 1 (2) (2)
Net Pension Cost 305 282 284
Early retirement benefits - 402 231
Total Pension Costs $ 305 $ 684 $ 515
The following table sets forth the plan's funded status, obligations, and
assumptions as of December 31, 1997 and 1996:
(Dollars in Thousands)
1997 1996
Accumulated benefit obligation:
Vested $11,865 $11,016
Non-vested 169 153
Total $12,034 $11,169
Projected benefit obligation $(14,685) $(13,041)
Fair value of assets 15,123 13,067
Funded status 438 26
Unrecognized prior
service costs 817 892
Unrecognized transition
amount (403) (481)
Unrecognized gain (2,445) (2,008)
Accrued Pension Cost $(1,593) $(1,571)
Assumptions:
Discount rate 7.0% 7.5%
Salary increases 4.5% 4.5%
Expected return on assets 8.5% 8.5%
On December 31, 1997, plan assets consisted of annuity contracts, equity and
debt securities, U.S. Treasury obligations, and cash equivalents.
Retirement Savings Plan
The Company has adopted a defined contribution plan (under Section 401(k)
of the Internal Revenue Code) covering substantially all of the Company's
employees. Participants may elect to defer from 1% to 15% of current
compensation, and the Company contributes such amounts to the plan. The Company
also matches contributions, with a maximum matching contribution of 1% of
current compensation. Participants are 100% vested at all times in
contributions made on their behalf. The Company's matching contributions to the
plan were approximately $55,000, $54,000, and $41,000 in 1997, 1996, and 1995,
respectively.
(Page 24)
Health Care Benefits
In addition to providing pension benefits, the Company provides certain
health care benefits to eligible employees and retirees. All employees share
in the cost of their medical benefits, in addition to plan deductibles and
coinsurance payments, approximately 14.5% in 1997. Effective with retirements
after January 1, 1995, only retirees with at least twenty years of service will
be eligible for these benefits. In addition, eligible retirees will contribute
to the cost of their coverage starting at 60% for retirees with twenty years of
service with the contribution phasing out over the next ten years of service
so that retirees with thirty or more years of service do not contribute toward
their coverage.
The components of net postretirement benefit costs are as follows:
(Dollars in Thousands)
1997 1996 1995
Service costs for benefits $103 $ 98 $ 97
Interest cost 343 321 365
Amortization of transition obligation 211 213 213
Total costs 657 632 675
Current payments for retiree obligations
allowed in Company's cost of service (217) (233) (207)
Additional SFAS 106 costs $440 $399 $468
Based on prior Maine Public Utilities Commission (MPUC) accounting orders,
the Company established a regulatory asset of approximately $1,061,000,
representing deferred postretirement benefits. As an element of its four-year
rate plan, the Company began recovering these deferred expenses over a ten-year
period, along with the annual expenses in excess of pay-as-you-go expenses,
starting in 1996. The MPUC requires the Company to establish and make payments
to an independent external trust fund for the purpose of funding future
postretirement health care costs at such time as customers are paying for
these costs in their rates. The Company has not established the external trust
fund, but will seek approval from the MPUC for a funding plan.
The Company's accumulated postretirement benefit obligation and funding
status consist of the following:
(Dollars in Thousands)
1997 1996
Retirees $(2,710) $(2,283)
Fully eligible actives (838) (1,295)
Other actives (1,385) (892)
Accumulated postretirement
benefit obligation (4,933) (4,470)
Transition obligation 3,181 3,394
Net gain (341) (762)
Accrued postretirement benefit cost $(2,093) $(1,838)
There were no unrecognized prior service costs. For 1997 and 1996, the
Company used an assumed weighted average discount rate of 7% and 7.5%,
respectively. The health care cost trend rate used for 1997 was 8%, with the
ultimate trend rate of 5% reached in two years. A one percentage-point increase
in the assumed health care cost trend rates for each future year would result
in an increase in the accumulated pension benefit obligation by $704,000, and
the aggregate of the service and the interest cost components of the net
periodic postretirement benefit cost for 1997 would increase by $78,000.
7. COMMON SHAREHOLDERS' EQUITY
The Maine Public Utilities Commission has authorized the repurchase of the
Company's Common Stock in order to maintain the Company's capital structure at
levels appropriate for an investor-owned electric utility. Under an open market
program that was extended through November, 1999, the Company has purchased
250,000 shares at a cost of $5.7 million, all of which are held as treasury
shares.
Under the most restrictive provisions of the Company's long-term debt
indentures and short-term credit arrangements, retained earnings (plus dividends
declared on Common Stock) available for the distribution of cash dividends on
Common Stock were $26,902,671 at December 31, 1997.
8. REFINANCING
On June 19, 1996, the Maine Public Utilities Financing Bank (MPUFB) issued
$15 million of its tax-exempt bonds due April 1, 2021 (the 1996 Series) on
behalf of the Company. The proceeds of the new 1996 Series were used to refund
a note from Fleet Bank of Maine, which was used to redeem the 1991 Series and
provided $5 million for the acquisition of qualifying property, of which $2.3
million remains in trust as of December 31, 1997. Pursuant to the long-term
note issued under a loan agreement between the Company and the MPUFB, the
Company has agreed to make payments to the MPUFB for the principal and interest
on the bonds. Concurrently, pursuant to a letter of credit and reimbursement
agreement, the Company caused a Direct Pay Letter of Credit for an initial term
of three years to be issued by the Bank of New York for the benefit of the
holders of such bonds. To secure the Company's obligations under the letter of
credit and reimbursement agreement, the Company issued a second mortgage bond
to the Bank of New York, as Agent, under the reimbursement agreement, in the
amount of $15,875,000. The Company has the option of selecting weekly, monthly,
annual or term interest rate periods for the 1996 Series, and has, since
issuance, selected the weekly interest period. After considering issuance costs
and credit enhancement fees, the effective interest rate since issuance as of
December 31, 1997 has been 5.705%.
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist primarily of cash in banks,
receivables, and debt. The carrying amounts for cash, receivables, and
short-term debt approximate their fair value due to the short-term nature of
these items. At December 31, 1997, the Company's long-term debt had a carrying
value of approximately $39.8 million and a fair value of approximately $43.0
million.
(Page 25)
10. COMMITMENTS, CONTINGENCIES, AND REGULATORY MATTERS
Four-Year Rate Plan Approved
On November 13, 1995, the Maine Public Utilities Commission (MPUC) approved
a stipulation signed by the Company, the Commission Staff, and the Maine Public
Advocate. This stipulation, effective January 1, 1996, established a multi-year
rate plan for the Company that provides our customers with predictable rates
through 1999 and shares operating risks and benefits between the Company's
shareholders and customers.
Under the terms of the stipulation, which applies cost of service principles,
the Company's retail rates were increased by 4.4% and 2.9% on January 1, 1996
and February 1, 1997, respectively. The Company has the right to receive
additional annual increases in retail rates of 2.75% on February 1, 1998 and
February 1, 1999. The Company has agreed that it will seek no other increases,
for either base or fuel rates, except as provided under the terms of the plan.
There will be no fuel clause adjustments for the duration of the plan.
The Company, under the terms of the plan, recognized write-offs in 1995,
totaling approximately $8,340,000, net of income taxes, or approximately $5.16
per share. As a result of the application of SFAS No. 101 "Accounting for the
Discontinuation of Application of FASB Statement No. 71", approximately
$4,846,000, net of income taxes, of the Company's investment in the Seabrook
nuclear project previously allocated to wholesale sales and $1,390,000, net of
income taxes, of other wholesale plant investment and regulatory assets have
been written off and classified as extraordinary items. The remaining segments
of the Company continue to meet the criteria of SFAS No. 71 "Accounting for the
Effects of Certain Types of Regulation". In addition, $2,104,000, net of income
taxes, of deferred retail fuel has been charged to operating expenses.
The Company will also be permitted to defer $1,500,000 annually of the costs
of its purchases from Wheelabrator-Sherman during each of the four years of the
rate plan. The plan permits the Company to recover this deferred amount, up to
a total of $6,000,000, in rates beginning in the year 2001. The rate plan
provides for the deferral, until the year 2000, of approximately $1.3 million,
net of income taxes, of uncollected retail fuel at the beginning of the rate
plan, while an additional $300,000, net of income taxes, will be collected in
rates over the rate plan period.
The increases are subject to adjustments resulting from the operation of a
profit-sharing mechanism, as well as the mandated cost and plant outage
provisions of the plan. The profit-sharing mechanism is based on a target
return on equity of 11%, calculated using certain retail ratemaking
methodologies, and is available for the rate increases in 1998 and 1999. The
profit-sharing mechanism establishes a bandwidth of 300 basis points around the
target return on equity. All gains or losses within that bandwidth will be
borne entirely by the Company's shareholders. Any earnings above or below the
bandwidth will be shared 50/50 by shareholders and customers. Moreover, the
Company is allowed to terminate the rate plan and file for a general rate
increase if its earnings fall 500 or more basis points below the target return
on equity during any twelve-month period during the term of the plan.
The plan also provides that if either Maine Yankee or Wheelabrator-Sherman
ceases operation for more than six months, the Company will be permitted to
adjust its allowed rate increases by half of the net costs or net savings
resulting from an outage. Any net costs or net savings realized during the
first six months of the outage would accrue entirely to shareholders. The
Company is also permitted to adjust the annual increases because of certain
mandated costs, such as tax or accounting changes, if any such change affects
the Company's annual revenue requirements by more than $300,000. The Company's
success under the rate plan was dependent on normal operation of Maine Yankee.
Maine Yankee owners voted to close the plant in August of 1997 and the
additional expenses associated with restarting and subsequently the efforts to
close the plant materially reduced the Company's earnings and cash flows. The
MPUC is awaiting the FERC's decision on Maine Yankee's FERC rate case before
addressing issues regarding the prudency of closing the nuclear power plant.
With these uncertainties concerning Maine Yankee, the Company negotiated with
the MPUC staff and the Public Advocate to modify the rate plan to deal with
these Maine Yankee costs and issues to assure reasonable rates for our customers
and reasonable returns to our stockholders.
On January 26, 1998, the MPUC approved a 3.9% February 1, 1998 rate increase,
according to terms of a stipulation agreed to by the Company and the Public
Advocate, with the support of the MPUC staff. The principal elements of the
agreement are as follows:
1. The rate increase effective February 1, 1998 was 3.9%, consisting of
the specified increase of 2.75% and approximately $562,000 of the 1997
recoverable Maine Yankee replacement power costs (1.15%);
2. The minimum rate increase effective February 1, 1999 will be 3.1%,
consisting of a specified increase of 2.0% and the remaining
recoverable 1997 Maine Yankee replacement power costs of $523,000;
3. Maine Yankee replacement power costs for the period October 1, 1997
through September 30, 1998 will be offset by the 1998 savings under
the restructured Wheelabrator-Sherman contract, with the recovery of
any incremental Maine Yankee replacement power costs subject to a
final order by the MPUC in its review of the prudency of closing Maine
Yankee;
4. The Company wrote off unamortized Maine Yankee refueling outage costs
of approximately $1,458,000 in 1997;
5. The Company waives its right to collect additional revenues for the
profit-sharing review period, i.e. the twelve months ended September
30, 1997, since the earnings deficiency was the result of the closing
of Maine Yankee and, based on the 3.9% increase granted by the MPUC,
the Company expects to earn a reasonable rate of return in 1998
without these additional revenues;
6. Maine Yankee replacement power costs for the period October 1, 1998
through February 29, 2000 will be deferred for subsequent recovery in
retail rates, subject to the MPUC's final order on its prudency
review.
The Company was not able to attain its interest coverage tests for the fourth
quarter of 1997, but the Banks have granted a waiver. For 1998, the Banks have
agreed to amend these interest coverage tests to deal with these additional
Maine Yankee costs. Based on the
(Page 26)
Company's current projections, the Company believes that it can attain these
amended interest coverage tests. The Company believes that its rate plan deals
effectively with the closing of Maine Yankee, with customers and shareholders
sharing the burden equally. However, the Company cannot predict what the MPUC's
decisions will be concerning the prudency of closing Maine Yankee. If the
Company is adversely impacted by the MPUC prudency decision, or if the Company
is unable to complete the financing for the restructured Wheelabrator-Sherman
contract, the Company may be required to seek an emergency rate increase and
will review all cash expenditures, including the level of dividends.
Discontinuance of SFAS 71 for Wholesale Business Segment
The wholesale market for electric power is now competitive, as evidenced by
the Company's loss of a major wholesale customer, Houlton Water Company. The
rates that the Company is now charging its remaining wholesale customers are
based on market pricing and not rate base/rate of return regulatory formulas.
For this reason, the Company has discontinued the application of Statement of
Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of
Certain Types of Regulation", for its wholesale segment of its business
jurisdiction. In accordance with the application of SFAS No. 101 "Accounting
for the Discontinuation of Application of FASB Statement No. 71", these
write-offs were classified as extraordinary items associated with the
discontinuance in 1995.
Industry Restructuring
On May 29, 1997, legislation titled "An Act to Restructure the State's
Electric Industry" was signed into law by the Governor of Maine. The principal
provisions with accounting impact on the Company are as follows:
1. Beginning on March 1, 2000, all consumers of electricity have the
right to purchase generation services directly from competitive
electricity suppliers who will not be subject to rate regulation.
2. By March 1, 2000, the Company, Central Maine Power Company (CMP), and
Bangor Hydro-Electric Company (BHE) must divest themselves of all
generation related assets and business functions except for:
a) contracts with qualifying facilities, such as the Company's power
contract with Wheelabrator-Sherman (W-S), and conservation
providers;
b) nuclear assets, namely, the Company's investment in the Maine
Yankee Atomic Power Company;
c) facilities located outside the United States, i.e., the Company's
hydro facility in New Brunswick, Canada; and
d) assets that the MPUC determines necessary for the operation of the
transmission and distribution services.
As required by the electric utility industry restructuring
legislation discussed above, the Company has offered for sale all of
its generating capacity, including its Canadian subsidiary, with a
total net book value of $11.0 million as of December 31, 1997. This
plan has been approved by the Maine Public Utilities Commission,
which must also approve the ultimate sale of these assets. The
Company believes it will take at least a full year to complete this
divestiture process, which began in late August, 1997. Bids for the
assets were solicited and collected on January 15, 1998, and
negotiations with current bidders are currently underway. The Company
cannot predict the final outcome of the proposed divestiture.
3. The Company, through a regulated affiliate, will continue to provide
transmission and distribution services which will be subject to
continued rate regulation by the MPUC.
4. Maine electric utilities will be permitted a reasonable opportunity
to recover legitimate, verifiable and unmitigable costs that are
otherwise unrecoverable as a result of retail competition in the
electric utility industry (so-called "stranded costs").
The MPUC shall determine these stranded costs by considering:
a) the utility's regulatory assets related to generation, i.e., the
Company's unrecovered Seabrook investment;
b) the difference between net plant investment in generation assets
compared to the market value for those assets; and
c) the difference between future contract payments and the market
value of the purchased power contracts, i.e., the W-S contract.
By July 1, 1999, the MPUC will have estimated the stranded costs
for the Company and the manner for the collection of these costs by
the transmission and distribution company. Customers reducing or
eliminating their consumption of electricity by switching to
self-generation, conversion to alternative fuels or utilizing
demand-side management measures cannot be assessed exit or entry fees.
The Company estimates its stranded costs to be approximately $85
million, based on the completion of the W-S contract restructuring,
market power estimates beyond 2000 and regulatory treatment of the
Company's remaining Seabrook investment, but does not include any
benefits from the Company's sale of generating assets.
5. The MPUC shall include in the rates charged by the transmission and
distribution utility decommissioning expenses for Maine Yankee. In
2003, and every three years thereafter until the stranded costs are
recovered, the MPUC shall review and adjust the stranded cost
recovery amounts and related transition charges. However, the MPUC
may adjust the amounts at any point in time that they deem
appropriate. Since the legislation provides for our recovery of
stranded costs by the transmission and distribution company, the
Company will continue to recognize existing regulatory assets and
plant costs as provided by Emerging Issues Task Force 97-4
"Deregulation of the Pricing of Electricity" (EITF 97-4).
6. Employees other than officers, displaced as a result of retail
competition will be entitled to certain severance benefits an
retraining programs. These costs will be recovered through charges
collected by the regulated transmission and distribution company.
The MPUC will conduct several rulemaking proceedings associated with the
new restructuring law. The Company is presently
(Page 27)
reviewing its business operations and the opportunities that the new
restructuring law presents.
In accordance with EITF 97-4 when all of the details of the restructuring
plan are determined by the MPUC rulemaking, the Company will discontinue
application of the Statement of Financial Accounting Standards No. 71 (SFAS 71),
"Accounting for the Effects of Certain Types of Regulations", for the generating
segment of its business jurisdiction. As a result, the Company continues to
defer certain costs as regulatory assets in instances where recovery through
future regulatory cash flows is anticipated.
Seabrook Nuclear Power Project
In 1986, the Company sold its 1.46% ownership interest in the Seabrook
Nuclear Power Project with a cost of approximately $92.1 million for $21.4
million. Both the MPUC and the FERC allowed recovery of the Company's remaining
investment in Seabrook Units 1 and 2, adjusted by disallowed costs and sale
proceeds, with the costs being amortized over thirty years.
With the adoption of the Company's rate plan and the discontinuance of SFAS
71 for the Company's wholesale business, as previously discussed, the Company
wrote off its remaining wholesale Seabrook costs of approximately $4,846,000,
net of income taxes, in 1995. Recoverable Seabrook costs at December 31, 1997
and 1996 are as follows:
(Dollars in Thousands)
1997 1996
Retail $43,136 $43,136
Accumulated Amortization (16,837) (15,414)
Retail, Net $26,299 $27,722
Nuclear Insurance
In 1988, Congress extended the Price-Anderson Act for fifteen years and
increased the maximum liability for a nuclear-related accident. In the event
of a nuclear accident, coverage for the higher liability now provided for by
commercial insurance coverage will be provided by a retrospective premium of up
to $79.3 million for each reactor owned, with a maximum assessment of $10
million per reactor for any year. These limits are also subject to inflation
indexing at five-year intervals as well as an additional 5% surcharge, should
total claims exceed funds available to pay such claims. Based on the Company's
5% equity ownership in Maine Yankee (see Note 3), the Company's share of any
retrospective premium would not exceed approximately $4.0 million or $.5 million
annually, without considering inflation indexing.
Capacity Arrangements
The Company owns 5% of the Common Stock of Maine Yankee, which operated an 860
MW nuclear power plant (the "Plant") in Wiscasset, Maine. On August 6, 1997,
the Board of Directors of Maine Yankee voted to permanently cease power
operations and to begin decommissioning the Plant. The Plant experienced a
number of operational and regulatory problems and has been shut down since
December 6, 1996. The decision to close the Plant permanently was based on
an economic analysis of the costs, risks and uncertainties associated with
operating the Plant compared to those associated with closing and
decommissioning it. The Plant's operating license from the Nuclear Regulatory
Commission (NRC) was due to expire on October 21, 2008.
The Plant generally provided reliable and low-cost power from the time it
commenced operations in late 1972 to 1995. Beginning in early 1995, however,
Maine Yankee encountered various operational and regulatory difficulties with
the Plant. In 1995, the Plant was shut down for almost the entire year to
repair a large number of steam generator tubes that were exhibiting defects.
Shortly before the Plant was to go back on-line in December 1995, a group with
a history of opposing nuclear power released an undated, unsigned, anonymous
letter alleging that in 1988 Yankee Atomic (then an affiliated consultant of
Maine Yankee) and Maine Yankee had used the results of a faulty computer code
as a basis to apply to the NRC for an increase in the Plant's power output. In
response to the allegation, on January 3, 1996, the NRC issued a Confirmatory
Order that restricted the Plant to 90 percent of its licensed thermal operation
level, which restriction was still in effect when the Plant was permanently shut
down.
As a result of the controversy associated with the allegations, the NRC, at
the request of the Governor of Maine, conducted an intensive Independent Safety
Assessment (ISA) of the Plant in the Summer and Fall of 1996. On October 7,
1996, the NRC issued its ISA report, which found that while the Plant had been
operated safely, there were weaknesses that needed to be addressed, which would
require substantial additional spending by Maine Yankee. On December 10, 1996,
Maine Yankee responded to the ISA report, acknowledged many of the weaknesses,
and committed to revising its operations and procedures to address the NRC's
criticisms.
Another result of the controversy associated with the allegations was an
investigation of Maine Yankee initiated by the NRC's Office of Investigations
(OI), which, in turn, referred certain issues to the United States Department
of Justice (DOJ) for possible criminal prosecution. Subsequently, on September
27, 1997, the DOJ, through the United States Attorney for Maine, announced that
its review had revealed no grounds for criminal prosecution. The Company
believes that the OI investigation, however, could ultimately result in the
imposition of civil penalties, including fines, on Maine Yankee.
In 1996, the Plant was generally in operation at the 90-percent level from
late January to early December, except for a two-month outage from mid-July to
mid-September. The Plant was shut down again on December 6, 1996, to address
several concerns, and has not operated since then. The precipitating event
causing the shutdown was the need to evaluate and resolve cable-separation
compliance issues, and on December 18, 1996, the NRC issued a Confirmatory
Action Letter requiring the Plant to remain shut down until Maine Yankee's plan
for resolving the cable-separation issues was accepted by the NRC.
Subsequently, Maine Yankee uncovered additional issues, including among others
the possibility of having to replace defective fuel assemblies, address
additional cable-separation issues, and determine the condition of the Plant's
steam generators, all of which contributed to further operational uncertainty.
On January 29, 1997, the Plant was placed on the NRC's Watch List, and on
January 30, 1997, the NRC issued a supplemental Confirmatory Action Letter
requiring the resolution of additional concerns before the Plant could be
restarted.
In December 1996, Maine Yankee requested proposals from several utilities with
large and successful nuclear programs to provide a management team, and
ultimately contracted with Entergy Nuclear, Inc., effective February 13, 1997,
for management services that included providing a new president and regulatory
compliance officer. The Entergy-provided management team made progress in
addressing technical issues, but a number of operational and regulatory
uncertainties remained. On May 27, 1997, the Board of Directors of Maine Yankee
voted to minimize spending while preserving the options of restarting the Plant
or conveying ownership interests to a third party. After unsuccessful
negotiations with one prospective purchaser, Maine
(Page 28)
Yankee found no other interest in purchasing the Plant and, based on its
economic analysis, closed the Plant permanently.
As required by the NRC, on August 7, 1997, Maine Yankee certified to the NRC
that Maine Yankee had permanently ceased operations and that all fuel assemblies
had been permanently removed from the Plant's reactor vessel. On August 27,
1997, Maine Yankee filed the required Post-Shutdown Activities Report with the
NRC, describing its planned post-shutdown activities and a proposed schedule.
The Company's 5% ownership interest in Maine Yankee's common equity amounted
to $4.0 million as of December 31, 1997, and under Maine Yankee's Power
Contracts and Additional Power Contracts, the Company is responsible for 5% of
the costs of decommissioning the Plant. Maine Yankee's most recent estimate of
the cost of decommissioning is $380.4 million, based on a 1997 study by an
independent engineering consultant, plus estimated costs of interim spent-fuel
storage of $127.6 million, for an estimated total cost of $508 million (in 1997
dollars). The previous estimate for decommissioning, by the same consultant,
was $316.6 million (in 1993 dollars).
On September 1, 1997, Maine Yankee estimated the sum of the future payments
for the closing, decommissioning and recovery of the remaining investment in
Maine Yankee to be approximately $930 million, of which the Company's 5% share
would be approximately $46.5 million. Legislation enacted in Maine in 1997
calling for restructuring the electric utility industry provides for recovery
of decommissioning costs, to the extent allowed by federal regulation, through
the rates charged by the transmission and distribution companies. Based on the
Maine legislation and regulatory precedent established by the FERC in its
opinion relating to the decommissioning of the Yankee Atomic nuclear plant, the
Company believes that it is entitled to recover substantially all of its share
of such costs from its customers and, as of December 31, 1997, is carrying on
its consolidated balance sheet a regulatory asset and a corresponding liability
in the amount of $43.4 million, which is the $46.5 million discussed above net
of the Company's post-September 1, 1997 cost-of-service payments to Maine
Yankee.
On September 2, 1997, the MPUC released the report of a consultant it had
retained to perform a management audit of Maine Yankee for the period January
1, 1994, to June 30, 1997. The report contained both positive and negative
conclusions, the latter including: that Maine Yankee's decision in December
1996 to proceed with the steps necessary to restart the Plant was "imprudent",
that Maine Yankee's May 27, 1997 decision to reduce restart expenses while
exploring a possible sale of the Plant was "inappropriate", based on the
consultant's finding that a more objective and comprehensive competitive
analysis at that time "might have indicated a benefit for restarting" the Plant;
and that those decisions resulted in Maine Yankee incurring $95.9 million in
"unreasonable" costs. The Company has expensed its share of these costs. On
October 24, 1997, the MPUC issued a Notice of Investigation initiating an
investigation of the shutdown decision and of the operation of the Plant prior
to shutdown, and announced that it had directed its consultant to extend its
review to include those areas. The Company does not know how the MPUC plans to
use the consultant's report, but believes the report's negative conclusions are
unfounded and may be contradictory. The Company believes it would have
substantial constitutional and jurisdictional grounds to challenge any effort
in an MPUC proceeding to alter wholesale Maine Yankee rates made effective by
the FERC. On November 7, 1997, Maine Yankee and Central Maine Power initiated
a legal challenge to the MPUC investigation in the Maine Supreme Judicial Court
alleging that such an investigation falls exclusively within the jurisdiction
of the FERC and that the MPUC investigation is therefore barred on
constitutional grounds. The Company joined in this appeal. The MPUC
subsequently stayed its investigation pending the outcome of Maine Yankee's FERC
rate case, while indicating that its consultant would continue its extended
review. The Maine Supreme Court, on motion of the parties, stayed the appeal
pending resolution of the FERC proceeding.
During 1997, the Company incurred Maine Yankee replacement power costs of
approximately $7,302,000, of which $2,324,000 has been deferred under the
Company's rate stabilization plan, and also incurred additional operating costs
of approximately $3.0 million associated with the efforts to restart and
subsequently close Maine Yankee, which have adversely impacted the Company's
earnings.
The February 1, 1998, rate increase included a portion of these recoverable
1997 Maine Yankee replacement power costs with the remaining costs included in
the February 1, 1999 rate increase. However, the collection of future Maine
Yankee replacement power costs will be subject to the MPUC's
previously-mentioned prudence review of the prudency of closing Maine Yankee.
On January 1, 1996 the Company placed Steam Units 1 and 2, totalling 23 MW,
of the generating facility in Caribou, Maine on inactive status. During the
Units' inactive period, the plant equipment will be protected and maintained by
the installation of a dehumidification system that will permit the units to
return to service in approximately six months. As discussed above, the Company
is seeking buyers for this and the other generating facilities as required by
the Industry Restructuring legislation.
The Company also owns 7.49% of the Common Stock of Maine Electric Power
Company, Inc., (MEPCO). MEPCO owns and operates a 345-KV (kilovolt)
transmission line about 180 miles long which connects the New Brunswick Power
(NB Power) system with the New England Power Pool. The MEPCO transmission line
is also the path by which Wyman Unit No. 4 energy is delivered northerly into
the NB Power system and then wheeled to the Parent Company through its
interconnection with NB Power at the international border.
In July, 1986, Wheelabrator-Sherman, formerly Signal-Sherman Energy Co. (W-S),
owner of an 17.6 MW wood-burning cogenerator plant, began selling power to the
Company. The Company purchases the entire output from the cogenerator under a
Purchase Power Agreement (PPA) ordered by the MPUC that will expire in 2001.
This PPA includes a 5% annual price increase. During 1997, 1996, and 1995,
purchases from W-S were $15,911,000, $15,593,000, and $14,507,000, respectively.
The Company has been attempting for several years to restructure the terms of
its current PPA. By agreement dated October 15, 1997, the Company and W-S have
finally amended the PPA. Under the terms of this amendment, W-S agreed to
reductions in the price of purchased power of approximately $10 million over the
PPA's current term in exchange for an up-front payment of $8.7 million. The
Company and W-S also agreed to renew the PPA for an additional six years at
agreed-upon prices. The Company believes the amended PPA will help relieve the
financial pressure caused by the recent closure of Maine Yankee as well as the
need for substantial increases in its retail rates, and is, therefore, in the
best interests of the Company, its customers, and shareholders.
(Page 29)
The Company intends to finance the up-front payment to W-S from funds obtained
from the Finance Authority of Maine (FAME). Absent FAME financing, the Company
does not believe it could obtain the funds on terms sufficiently economic to
justify the arrangement with W-S. In its filing with MPUC, the Company further
asked the MPUC for a determination that any so-called stranded cost created by
the amended PPA will be recoverable from customers to the extent permitted by
Maine law.
On December 22, 1997, the MPUC approved the amended purchase power agreement
and determined that the up-front costs created by the amended PPA will be
treated as stranded cost and, therefore, recovered in rates of the transmission
and distribution company. On February 19, 1998, the Board of Directors of FAME
authorized the issuance and sale of securities under FAME's electric rate
stabilization program. The Company expects to complete the financing during the
second quarter of 1998.
On December 19, 1997, the Company announced the signing of an agreement for
the purchase of power until 2000 from Alternative Energy's Beaver Power Plant
in Ashland, Maine, as a replacement for Maine Yankee energy.
Construction Program
Expenditures on additions, replacements and equipment for the years ended
December 31, 1997, 1996, and 1995, along with 1998 estimated expenditures, are
as follows:
(Dollars in Thousands) 1998 1997 1996 1995
(Unaudited Estimates)
Parent Company
Generation $15 $92 $345 $131
Transmission 757 491 322 364
Distribution 2,688 1,636 2,080 1,993
General 714 425 626 845
Total Parent 4,174 2,644 3,373 3,333
Subsidiary 32 80 72 96
Total $4,206 $2,724 $3,445 $3,429
11. QUARTERLY INFORMATION (unaudited)
Quarterly financial data for the two years ended December 31, 1997 is as
follows:
(Dollars in Thousands Except Per Share Amounts)
1997 by Quarter
1st 2nd 3rd 4th
Operating revenues $15,368 $12,339 $12,385 $14,980
Operating expenses (14,847) (11,871) (12,773) (14,670)
Operating income 521 468 (388) 310
Interest charges (848) (888) (894) (953)
Other income-net 73 67 153 202
Net income $(254) $(353) $(1,129) $(441)
Earnings per common share $(0.16) $(0.22) $(0.70) $(0.27)
1996 by Quarter
1st 2nd 3rd 4th
Operating revenues $15,625 $14,780 $12,763 $14,096
Operating expenses (13,330) (13,397) (12,627) (12,622)
Operating income 2,295 1,383 136 1,474
Interest charges (922) (851) (875) (878)
Other income-net 78 77 84 110
Net income $1,451 $609 $(655) $706
Earnings per common share $0.90 $0.38 $(0.41) $0.44
(Page 30 and 31)
MAINE PUBLIC SERVICE COMPANY
and Subsidiary (Unaudited)
All share information and per share amounts reflect the stock split on March 3,
1989.
Consolidated Financial Statistics
1997 1996 1995
Capitalization Including Bank Borrowings (year-end)
Debt (including amount due within
one year) 57.82% 52.75% 49.92%
Preferred Stock (including amount due
within one year) 0% 0% 0%
Common Shareholders' Equity 42.18% 47.25% 50.08%
Times Interest Earned - *
Before Income Taxes 0.14 2.18 2.51
After Income Taxes 0.39 1.60 1.80
Times Interest and Preferred Dividends
Earned - *
After Income Taxes 0.39 1.60 1.80
Embedded Cost of Long-Term Debt (year-end) 7.96% 8.01% 9.36%
Embedded Cost of Preferred Stock (year-end) 0% 0% 0%
Common Shares Outstanding (year-end) 1,617,250 1,617,250 1,617,250
Basic Earnings Per Share of Common Stock (average shares)
Income Before Cumulative Effect of
Accounting Change and Extraordinary
Items $(1.35) $1.31 $ .57
Cumulative Effect of Accounting Change - - -
Extraordinary Items - - (3.86)
Net Income (Loss) $(1.35) $1.31 $(3.29)
Dividends Per Share of Common Stock
Declared Basis $1.00 $1.84 $1.84
Paid Basis $1.21 $1.84 $1.84
Common Stock Dividend Payout Ratio - ** - 140.46% 98.40%
Book Value Per Share of Common Stock
(year-end) $21.21 $23.55 $ 24.09
Market Price Per Share of Common Stock
High $18 3/8 $22 3/8 $23 7/8
Low $10 1/4 $16 7/8 $19 7/8
Close $12 $18 1/8 $21 3/8
Price Earnings Ratio (year-end) + - 13.84 -
Number of Common Shareholders
(year-end) 1,436 1,619 1,634
Consolidated Financial Statistics
1994 1993 1992 1991
Capitalization Including Bank Borrowings (year-end)
Debt (including amount due within
one year) 44.25% 45.83% 50.16% 53.01%
Preferred Stock (including amount due
within one year) 0% 0% 0% 0%
Common Shareholders' Equity 55.75% 54.17% 49.84% 46.99%
Times Interest Earned - *
Before Income Taxes 3.25 3.49 3.01 2.81
After Income Taxes 2.26 2.36 2.09 2.00
Times Interest and Preferred Dividends
Earned - *
After Income Taxes 2.26 2.36 2.09 2.00
Embedded Cost of Long-Term Debt (year-end) 9.36% 9.14% 9.14% 9.28%
Embedded Cost of Preferred Stock (year-end) 0% 0% 0% 0%
Common Shares Outstanding (year-end) 1,617,250 1,660,250 1,660,250 1,660,250
Basic Earnings Per Share of Common Stock (average shares)
Income Before Cumulative Effect of
Accounting Change and Extraordinary
Items $2.99 $3.19 $2.93 $2.62
Cumulative Effect of Accounting Change - - - -
Extraordinary Items - - - -
Net Income (Loss) $2.99 $3.19 $2.93 $2.62
Dividends Per Share of Common Stock
Declared Basis $1.84 $1.78 $1.76 $1.68
Paid Basis $l.84 $l.76 $1.74 $1.68
Common Stock Dividend Payout Ratio - ** 61.54% 55.80% 60.07% 64.12%
Book Value Per Share of Common Stock
(year-end) $29.22 $28.02 $26.61 $25.44
Market Price Per Share of Common Stock
High $27 3/8 $31 1/4 $26 7/8 $26 3/8
Low $20 1/2 $25 5/8 $24 1/4 $20 3/4
Close $20 3/4 $25 7/8 $25 7/8 $26 3/8
Price Earnings Ratio (year-end) + 6.94 8.11 8.83 10.07
Number of Common Shareholders
(year-end) 1,650 1,720 1,768 1,823
Consolidated Financial Statistics
1990 1989 1988 1987
Capitalization Including Bank Borrowings (year-end)
Debt (including amount due within
one year) 49.40% 43.12% 47.76% 49.32%
Preferred Stock (including amount due
within one year) 0% 0% 0% 0%
Common Shareholders' Equity 50.60% 52.86% 47.83% 42.36%
Times Interest Earned - *
Before Income Taxes 3.24 3.21 3.07 2.27
After Income Taxes 2.22 2.26 2.29 1.69
Times Interest and Preferred Dividends
Earned - *
After Income Taxes 2.18 2.09 2.05 1.49
Embedded Cost of Long-Term Debt (year-end) 9.92% 9.71% 10.80% 10.98%
Embedded Cost of Preferred Stock (year-end) 0% 9.74% 9.74% 11.20%
Common Shares Outstanding (year-end) 1,761,050 1,849,550 1,865,666 1,862,478
Basic Earnings Per Share of Common Stock (average shares)
Income Before Cumulative Effect of
Accounting Change and Extraordinary
Items $2.58 $2.71 $3.12 $1.59
Cumulative Effect of Accounting Change - - - .45
Extraordinary Items - - - -
Net Income (Loss) $2.58 $2.71 $3.12 $2.04
Dividends Per Share of Common Stock
Declared Basis $1.68 $1.575 $1.175 $ .80
Paid Basis $l.66 $l.55 $1.025 $ .75
Common Stock Dividend Payout Ratio - ** 65.12% 58.12% 37.66% 39.22%
Book Value Per Share of Common Stock
(year-end) $24.38 $23.39 $22.26 $20.41
Market Price Per Share of Common Stock
High $23 3/8 $24 7/8 $20 13/16 $15 7/16
Low $19 1/2 $20 5/16 $11 7/8 $11 1/2
Close $22 1/4 $22 3/8 $20 1/2 $12 9/16
Price Earnings Ratio (year-end) + 8.62 8.26 6.57 6.16
Number of Common Shareholders
(year-end) 2,061 1,919 1,933 2,045
* Consolidated income before cumulative effect of accounting change and
extraordinary items. Includes AFUDC and Deferred Return on Seabrook
Investment. Excludes all regulatory write-offs in 1995.
** 1997 net loss produces a ratio which is not meaningful. Before regulatory
write-offs in 1995.
+ 1997 and 1995 net losses produce ratios which are not meaningful.
(Circle Charts)
1997 Sources of Income
Millions of Dollars (Total $55.6) and Percent of Total
Residential
$20.4 Million [36.7%]
Commercial
$17.4 Million [31.3%]
Industrial
$9.5 Million [17.1%]
Other Electric Sales
$5.8 Million [10.4%]
Other Income
$2.5 Million [4.5%]
1997 Distribution of Income
Millions of Dollars (Total $55.6) and Percent of Total
Fuel & Purchased Power
$37.5 Million [67.4%]
Wages and Employee Benefits
$6.9 Million [12.4%]
Taxes
$0.6 Million [1.1%]
Other Operating Expenses
$9.2 Million [16.5%]
Interest
$3.6 Million [6.5%]
Common Dividends
$1.6 Million [2.9%]
Retained Earnings
$(3.8) Million [(6.8%)]
Year-End Capitalization Chart
(Page 32 and 33)
MAINE PUBLIC SERVICE COMPANY
and Subsidiary (Unaudited)
Consolidated Operating Statistics
1997 1996 1995
Operating Revenues
Residential $20,391,688 $19,961,192 $19,080,662
Commercial and Industrial - Small 17,418,761 16,420,167 15,723,439
Commercial and Industrial - Large 9,452,158 10,111,758 9,437,409
Municipal Street Lighting 546,071 538,890 524,616
Area Lighting 268,208 273,985 272,896
Other Municipal and Other
Public Authorities 653,563 710,106 903,370
Other Electric Utilities 4,307,528 6,893,598 7,573,360
Other Operating Revenues 2,034,219 2,354,469 1,762,974
Total Operating Revenues $55,072,196 $57,264,165 $55,278,726
Number of Customers (average)
Residential 28,561 28,515 28,385
Commercial and Industrial - Small 5,586 5,541 5,465
Commercial and Industrial - Large 15 15 15
Municipal Street Lighting 39 38 38
Area Lighting 1,063 1,059 1,048
Other Municipal and Other
Public Authorities 5 5 5
Other Electric Utilities 11 10 9
Total Customers 35,280 35,183 34,965
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 26,758 10,201 22,867
Hydro 107,734 168,993 121,252
Diesel (429) (674) 1,046
Purchases:
Nuclear Generated - 249,083 9,718
Fossil Fuel Generated 496,888 372,431 508,266
Inadvertent Received (Delivered) (494) 741 (1,449)
Total 630,457 800,775 661,700
Losses, Unaccounted for and Unbilled 34,128 33,303 36,411
Company Use 1,695 1,517 1,490
Electricity Sold 594,634 765,955 623,799
Sales:
Residential 167,368 169,298 168,640
Commercial and Industrial-Small 168,976 163,804 165,914
Commercial and Industrial-Large 134,741 134,588 128,478
Municipal Street Lighting 1,676 1,658 1,655
Area Lighting 1,443 1,418 1,457
Other Municipal and Other Public
Authorities 10,204 10,090 11,747
Other Electric Utilities 110,226 285,099 145,908
Total Sales 594,634 765,955 623,799
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 5,860 5,937 5,941
Revenue $ 713.97 $ 700.02 $ 672.21
Revenue per Kilowatt-hour 12.18c 11.79c 11.31c
MAINE PUBLIC SERVICE COMPANY
and Subsidiary (Unaudited)
Consolidated Operating Statistics
1994 1993 1992 1991
Operating Revenues
Residential $19,646,681 $19,669,749 $18,704,900 $19,194,469
Commercial and Industrial
- Small 15,614,453 15,177,992 13,787,720 13,991,693
Commercial and Industrial
- Large 9,225,131 9,554,566 8,891,123 10,105,693
Municipal Street Lighting 517,793 512,439 499,814 512,640
Area Lighting 271,115 269,925 261,984 267,518
Other Municipal and Other
Public Authorities 2,105,933 3,597,514 3,761,815 3,977,098
Other Electric Utilities 8,481,483 9,188,561 8,150,094 7,328,914
Other Operating Revenues 2,505,496 2,505,466 2,626,190 2,460,062
Total Operating Revenues $58,368,085 $60,476,212 $56,683,640 $57,838,087
Number of Customers (average)
Residential 28,300 28,220 28,102 28,052
Commercial and Industrial-Small 5,418 5,364 5,261 5,205
Commercial and Industrial-Large 16 16 15 15
Municipal Street Lighting 38 38 38 38
Area Lighting 1,048 1,061 1,075 1,091
Other Municipal and Other
Public Authorities 8 8 8 8
Other Electric Utilities 9 8 7 7
Total Customers 34,837 34,715 34,506 34,416
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 18,559 26,456 33,509 28,868
Hydro 118,759 148,719 130,407 135,619
Diesel (153) 169 (636) (178)
Purchases:
Nuclear Generated 326,334 282,199 263,313 307,769
Fossil Fuel Generated 290,172 288,487 300,930 246,172
Inadvertent Received (Delivered) 651 (1,053) (2,232) 1,861
Total 754,322 744,977 725,291 720,111
Losses, Unaccounted for and
Unbilled 42,880 43,944 43,686 42,114
Company Use 1,518 1,542 1,462 1,499
Electricity Sold 709,924 699,491 680,143 676,498
Sales:
Residential 175,685 176,732 176,814 176,028
Commercial and Industrial
-Small 167,485 162,949 155,267 149,709
Commercial and Industrial
-Large 127,327 135,029 129,981 139,931
Municipal Street Lighting 1,642 1,630 1,864 2,336
Area Lighting 1,472 1,482 1,538 1,591
Other Municipal and Other
Public Authorities 28,621 53,021 58,388 57,687
Other Electric Utilities 207,692 168,648 156,291 149,216
Total Sales 709,924 699,491 680,143 676,498
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 6,208 6,263 6,292 6,275
Revenue $ 694.23 $ 697.01 $ 665.61 $ 684.25
Revenue per Kilowatt-hour 11.18c 11.13c 10.58c 10.90c
MAINE PUBLIC SERVICE COMPANY
and Subsidiary (Unaudited)
Consolidated Operating Statistics
1990 1989 1988 1987
Operating Revenues
Residential $18,189,325 $18,537,902 $17,787,713 $15,948,095
Commercial and Industrial
- Small 12,708,677 13,379,207 12,374,719 10,700,466
Commercial and Industrial
- Large 10,115,772 9,785,058 9,673,266 7,736,051
Municipal Street Lighting 505,063 573,351 559,478 541,853
Area Lighting 262,845 288,378 285,979 273,570
Other Municipal and Other
Public Authorities 3,611,220 3,736,851 3,546,473 2,955,417
Other Electric Utilities 9,649,398 10,980,817 9,244,874 8,735,459
Other Operating Revenues 1,701,167 (62,314) 649,746 527,707
Total Operating Revenues $56,743,467 $57,219,250 $54,122,248 $47,418,618
Number of Customers (average)
Residential 27,983 27,737 27,358 27,074
Commercial and Industrial-Small 5,108 4,940 4,866 4,789
Commercial and Industrial-Large 15 17 18 17
Municipal Street Lighting 38 38 37 37
Area Lighting 1,114 1,155 1,166 1,238
Other Municipal and Other
Public Authorities 8 8 8 8
Other Electric Utilities 7 8 7 7
Total Customers 34,273 33,903 33,460 33,170
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 59,252 91,361 81,583 71,649
Hydro 176,832 106,571 112,953 100,158
Diesel (186) 2,664 1,933 572
Purchases:
Nuclear Generated 253,321 369,315 266,851 215,006
Fossil Fuel Generated 289,177 217,166 299,838 327,016
Inadvertent Received (Delivered) (151) 1,611 (677) (432)
Total 778,245 788,688 762,481 713,969
Losses, Unaccounted for and
Unbilled 40,613 42,474 44,883 43,377
Company Use 1,559 1,723 1,555 1,472
Electricity Sold 736,073 744,491 716,043 669,120
Sales:
Residential 178,011 178,668 176,680 173,580
Commercial and Industrial
-Small 146,881 145,364 139,220 131,535
Commercial and Industrial
-Large 155,782 145,307 148,220 133,405
Municipal Street Lighting 2,697 2,722 2,695 2,744
Area Lighting 1,643 1,580 1,585 1,626
Other Municipal and Other
Public Authorities 57,034 59,190 59,268 56,180
Other Electric Utilities 194,025 211,660 188,375 170,050
Total Sales 736,073 744,491 716,043 669,120
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 6,361 6,442 6,458 6,411
Revenue $ 650.01 $ 668.35 $ 650.18 $ 589.06
Revenue per Kilowatt-hour 10.22c 10.38c 10.07c 9.19c
(Page 34)
Independent Accountants' Report
MAINE PUBLIC SERVICE COMPANY:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Maine Public Service Company and its Subsidiary, Maine and
New Brunswick Electrical Power Company, Limited, as of December 31, 1997 and
1996, and the related consolidated statements of operations, common
shareholders' equity, and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based
on our audits. The consolidated financial statements of Maine Public Service
Company and its Subsidiary for the year ended December 31, 1995 were audited by
other auditors, whose report dated February 14, 1996, expressed an unqualified
opinion on those statements.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the 1997 and 1996 consolidated financial statements present
fairly, in all material respects, the consolidated financial position of Maine
Public Service Company and its Subsidiary as of December 31, 1997 and 1996 and
the results of their operations and their cash flows for the years then ended
in conformity with generally accepted accounting principles.
Coopers & Lybrand, L.L.P.
Portland, Maine
February 13, 1998
(Page 35)
Board of Directors
Maine Public Service
Company's ten-member
Board of Directors is
composed of nine outside
directors and one inside
director, Paul R. Cariani.
Their diverse business,
educational, professional,
and civic backgrounds are
valuable assets that provide
a broad perspective to the
issues concerning the
Company.
G. Melvin Hovey
Chairman of the Board
and Retired President
Maine Public Service Company
Presque Isle, Maine
Pension Investment Committee
Budget and Finance Committee
Robert E. Anderson
President
F. A. Peabody Company
Houlton, Maine
Pension Investment Committee
Budget and Finance Committee
Paul R. Cariani
President and CEO
Maine Public Service Company
Presque Isle, Maine
Nominating Committee
Donald F. Collins
Director and Retired President
S. W. Collins Co.
Caribou, Maine
Audit Committee
Nominating Committee
D. James Daigle
President
D & D Management Co.
Orlando, Florida
Executive Compensation Committee
Richard G. Daigle
President and CEO
Daigle Oil Company
Cold Brook Energy, Inc., President
Fort Kent, Maine
Audit Committee
Executive Compensation Committee
J. Gregory Freeman
President and CEO
Pepsi-Cola Bottling Company
of Aroostook, Inc.
Presque Isle, Maine
Budge and Finance Committee
Nominating Committee
Deborah L. Gallant
President and CEO
D. Gallant Management Associates
Portland, Maine
Executive Compensation Committee
Nathan L. Grass
President
Grassland Equipment, Inc.
Presque Isle, Maine
Executive Compensation Committee
J. Paul Levesque
President and CEO
J. Paul Levesque & Sons, Inc.
(Lumber Mill) and
Antonio Levesque & Sons, Inc.
(Logging Operation)
Ashland, Maine
Audit Committee
Pension Investment Committee
(Page 36)
Executive Officers
Paul R. Cariani
President & Chief Executive Officer
Frederick C. Bustard
Vice President
Power Supply & Environment
Larry E. LaPlante
Vice President
Finance, Administration, & Treasurer
Stephen A. Johnson
Vice President
Customer Service & General Counsel
Peter C. Louridas
Assistant To The President
Michael A. Thibodeau
Assistant Vice President
Human Resources
Kurt A. Tornquist
Controller, Assistant Treasurer
& Assistant Secretary
Walter J. Elish
Director of Economic Development
Transfer Agent
The Bank of New York
Shareholder Relations Dept. - 11E
P. O. Box 11258, Church Street Station
New York, NY 10286
Tel. No. 1-800-524-4458
E-Mail: Shareowner-svcs@bankofny.com
Stock Registrar
The Bank of New York
Annual Meeting
Tuesday, May 12, 1998
Form 10-K
The Company will provide shareholders
with copies of the Form 10-K upon request.
Director and Officer Changes
Your Company's Board of Directors suffered a great loss with the untimely death
of Walter M. Reed, Jr., on August 21, 1997. The vacancy will not be filled
immediately, reducing the number to ten on the Board of Directors. His
responsibilities on the Pension Investment Committee and Budget and Finance
Committee have been reassigned to other Directors. Walter served on the Board
for 18 years and was truly an outstanding business and community leader. He was
a valuable source of experience, insight, and advice and will be greatly missed.
(Graphic)
Crown of Maine
Maine Public Service Company
209 State Street
P. O. Box 1209
Presque Isle, Maine 04769-1209
Tel. No. (207) 768-5811
FAX No. (207) 764-6586
Home Page: http://www.mainerec.com/mpsco.html
E-Mail: mainepub@ mfx.net
Exhibit 99(l)
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders
of Maine Public Service Company
Presque Isle, Maine
We have audited the consolidated statements of operations, common shareholders'
equity, and cash flows of Maine Public Service Company and its Subsidiary, Maine
and New Brunswick Electrical Power Company, Limited, for the year ended December
31, 1995, listed in the Index at Item 14. Our audit also included the financial
statement schedule for the year ended December 31, 1995 listed in the Index at
Item 14. These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express
an opinion on the financial statements and financial statement schedule based
on our audit.
We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the results of operations and cash flows of Maine Public
Service Company and its subsidiary for the year ended December 31, 1995, in
conformity with generally accepted accounting principles. Also, in our opinion,
such financial statement schedule for the year ended December 31, 1995, when
considered in relation to the basic consolidated financial statements taken as
a whole, presents fairly in all material respects the information set forth
therein.
/s/ Deloitte & Touche LLP
Boston, Massachusetts
February 14, 1996
Exhibit 99(m)
AMENDMENT NO. 1
to the
LETTER OF CREDIT AND REIMBURSEMENT AGREEMENT
AMENDMENT NO. 1, dated as of March 28, 1997, to the
Letter of Credit and Reimbursement Agreement, dated as of
June 1, 1996, among Maine Public Service Company, The Bank of
New York, Fleet Bank of Maine, and The Bank of New York, as
Agent and Issuing Bank (the "Reimbursement Agreement").
Capitalized terms used herein which are defined in the
Reimbursement Agreement shall have the meanings defined
therein.
The parties hereto wish to amend the Reimbursement
Agreement in the manner and with the effect set forth herein.
Accordingly, the parties hereto agree as follows:
Section 1. Subject to the provisions of Section 2 below,
Section 1.01 of the Reimbursement Agreement is amended,
effective as of the date of this Amendment, by deleting the
definition of "Consolidated Net Income Available for Fixed
Charges" in its entirety and substituting therefor the
following definition:
"Consolidated Net Income Available for Fixed
Charges" means, for any specified period, the
consolidated income or loss before extraordinary items of
the Company and its Subsidiaries for such period,
determined in accordance with GAAP, plus (i) Consolidated
Interest Expense for such period, plus (ii) the provision
for income taxes for such period, minus (iii) the
allowance for equity funds used during construction for
such period, plus (iv) with respect to any period ending
after December 31, 1996, (A) the sum of $598,692 if such
period includes the three months ended September 30,
1996, (B) the sum of $553,897 if such period includes the
three months ended December 31, 1996, and (C) if such
period includes any of the three month periods ended
March 31, 1997, June 30, 1997 or September 30, 1997, an
amount equal to the incremental cost to the Company of
purchased power during each of the relevant three-month
periods resulting from the unavailability during such
periods of purchased power from the nuclear power plant
operated by Maine Yankee Atomic Power Company.
Section 2. (a) The continued effectiveness of the
amendment provided for in Section 1 of this Amendment shall be
subject to the condition subsequent that the Company shall
have complied on or before May 15, 1997 (the "Repeal Date")
with all of the conditions set forth in Section 2(a) of
Amendment No. 4, dated as of March 28, 1997, to the Revolving
Credit Agreement (the "Amendment Conditions").
(b) In the event that the Amendment Conditions
shall not have been satisfied on or before the Repeal Date,
(1) the amendment set forth in Section 1 of this Amendment
shall be repealed, effective retroactively to the date of this
Amendment and shall be deemed never to have occurred or been
effective for any purpose under the Reimbursement Agreement,
and (2) any and all certifications delivered by the Company to
the Agent and the Banks containing or based on calculations
performed in accordance with the Reimbursement Agreement as
amended by this Amendment shall be void and of no effect, and
the Company promptly shall deliver to the Agent and the Banks
revised certifications containing or based on calculations
performed in accordance with the Reimbursement Agreement as in
effect on the day prior to the date of this Amendment.
Section 3. In connection with this Amendment, the
Company agrees to pay to the Agent certain fees as set forth
in a letter agreement, dated March 26, 1997, between the
Company and the Agent.
Section 4. Except as amended hereby, the Reimbursement
Agreement shall remain in full force and effect.
Section 5. This Amendment shall be governed by, and
construed in accordance with, the internal laws of the State
of New York without regard to principals of conflict of laws.
Section 6. By its execution hereof, the Company hereby
certifies that the representations and warranties contained in
Section 4.01 of the Reimbursement Agreement are true and
correct as of the date hereof, except such thereof as
specifically refer to an earlier date.
Section 7. This Amendment may be executed in any number
of counterparts, each of which shall be an original and all of
which together shall constitute one amendment. It shall not
be necessary in making proof of this Amendment to produce or
account for more than one counterpart containing the signature
of the party to be charged.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment to be duly executed as of the date first above
written.
MAINE PUBLIC SERVICE COMPANY
By: ________________________
Title: _____________________
THE BANK OF NEW YORK,
individually and as Agent
and Issuing Bank
By: _________________________
Title: ______________________
FLEET BANK OF MAINE
By: _________________________
Title: ______________________
Exhibit 99(n)
AMENDMENT NO. 4
to the
REVOLVING CREDIT AGREEMENT
AMENDMENT NO. 4, dated as of March 28, 1997, to the
Revolving Credit Agreement, dated as of October 8, 1987, by
and among Maine Public Service Company, the signatory Banks
thereto and The Bank of New York, as Agent, as amended by
Amendment No. 1, dated as of October 8, 1989, Amendment No. 2,
dated as of May 11, 1992 and Amendment No. 3, dated as of
October 8, 1995 (the "Agreement").
Capitalized terms used herein which are defined in the
Agreement shall have the meanings defined therein.
The parties hereto wish to amend the Agreement in the
manner and with the effect set forth herein. Accordingly, the
parties hereto agree as follows:
Section 1. Subject to the provisions of Section 2 below,
paragraph 1 of the Agreement is amended, effective as of the
date of this Amendment, by deleting the definition of "Net
Income Available for Fixed Charges" in its entirety and
substituting therefor the following definition:
"Net Income Available for Fixed Charges" shall mean,
for any period, net income for such period, adjusted (i)
by subtracting any Allowance for Funds Used During
Construction and any Deferred Return on Seabrook
Investment, (ii) by adding interest charges and federal
and state income taxes, and (iii) with respect to any
period ending after December 31, 1996, by adding (A) the
sum of $598,692 if such period includes the three months
ended September 30, 1996, (B) the sum of $553,897 if such
period includes the three months ended December 31, 1996,
and (C) if such period includes any of the three month
periods ended March 31, 1997, June 30, 1997 or
September 30, 1997, an amount equal to the incremental
cost to the Company of purchased power during each of the
relevant three-month periods resulting from the
unavailability during such periods of purchased power
from the nuclear power plant operated by Maine Yankee.
Section 2. (a) The continued effectiveness of the
amendment provided for in Section 1 of this Amendment shall be
subject to the condition subsequent that the Company shall
have delivered all of the following documents and instruments
to the Agent (with a copy of items (ii), (iii), (iv) and (v)
for each Bank) on or before May 15, 1997 (the "Repeal Date"):
(i) a duly executed and authenticated First
Mortgage and Collateral Trust Bond, Series due 2005, of
the Company in the principal amount of $11,000,000 (the
"Bank Mortgage Bond"), registered in the name of the
Agent, and issued under and pursuant to the Indenture of
Mortgage and Deed of Trust, dated as of October 1, 1945
between the Company and First Trust National Association
(successor to Continental Illinois National Bank and
Trust Company of Chicago), as Trustee (the "Trustee"), as
heretofore supplemented, amended and modified (the "First
Mortgage Indenture") and as supplemented by the
Supplemental Indenture (as hereinafter defined), and;
(ii) an executed copy of a Seventeenth Supplemental
Indenture (the "Supplemental Indenture") to the First
Mortgage Indenture, providing for the issuance of the Bank
Mortgage Bond to secure the obligations of the Company to
the Banks and the Agent under the Agreement; and a copy
of each document delivered by or to the Company and the
Trustee in connection with the issuance, authentication
and delivery of the Bank Mortgage Bond;
(iii) originals (or copies certified to be true
copies by the Secretary or an Assistant Secretary of the
Company) of all governmental and regulatory approvals
(including, without limitation, approvals or orders of
the PUC) necessary for the Company to enter into this
Amendment and the Supplemental Indenture and to issue and
deliver the Bank Mortgage Bond;
(iv) Evidence satisfactory to the Agent that the
Supplemental Indenture and any other documents
(including, without limitation, financing statements)
required to be recorded or filed in order to convey and
create in favor of the Trustee for the benefit of the
holder of the Bank Mortgage Bond, a perfected lien on and
security interest in the property of the Company subject
to the lien of the First Mortgage Indenture, as
supplemented by the Supplemental Indenture, have been
properly recorded and/or filed in each office in each
jurisdiction required in order to create a perfected lien
on and security interest in such property, and that all
necessary recordation and filing fees and all documentary
taxes or other expenses related to such filings or
recordations have been paid in full; and
(v) An opinion of Verrill & Dana, counsel to the
Company, dated the date of issuance of the Bank Mortgage
Bond, covering the matters set forth in, and otherwise
complying with Exhibit A hereto, and covering such other
matters as the Agent may reasonably request.
(b) In the event that all of the documents set
forth in Section 2(a), in form and substance satisfactory to
the Agent, shall not have been delivered to the Agent on or
before the Repeal Date, (1) the amendment set forth in Section
1 of this Amendment shall be repealed, effective retroactively
to the date of this Amendment and shall be deemed never to
have occurred or been effective for any purpose under the
Agreement, and (2) any and all certifications delivered by the
Company to the Agent and the Banks containing or based on
calculations performed in accordance with the Agreement as
amended by this Amendment shall be void and of no effect, and
the Company promptly shall deliver to the Agent and the Banks
revised certifications containing or based on calculations
performed in accordance with the Agreement as in effect on the
day prior to the date of this Amendment.
Section 3. In connection with this Amendment, the
Company agrees to pay to the Agent certain fees as set forth
in a letter agreement, dated March 26, 1997, between the
Company and the Agent.
Section 4. Notwithstanding the fulfillment or
nonfulfillment of the conditions set forth in Section 2(a) of
this Amendment, paragraph 11 of the Agreement is amended by
deleting the addresses or "the Agent" and "the Banks" and
substituting therefor the following:
the Agent:
The Bank of New York, as Agent
One Wall Street
New York, New York 10286
Attention: John W. Hall,
Vice President
the Banks:
The Bank of New York
One Wall Street
New York, New York 10286
Attention: John W. Hall,
Vice President
Fleet Bank of Maine
80 Exchange Street
P.O. Box 923
Bangor, Maine 04402-0923
Attention: Neil C. Buitenhuys,
Vice President
Section 5. Except as amended hereby, the Agreement shall
remain in full force and effect.
Section 6. This Amendment shall be governed by, and
construed in accordance with, the internal laws of the State
of New York without regard to principals of conflict of laws.
Section 7. By its execution hereof, the Company hereby
certifies that the representations and warranties contained in
paragraph 4 of the Agreement are true and correct as of the
date hereof, except such thereof as specifically refer to an
earlier date.
Section 8. This Amendment may be executed in any number
of counterparts, each of which shall be an original and all of
which together shall constitute one amendment. It shall not
be necessary in making proof of this Amendment to produce or
account for more than one counterpart containing the signature
of the party to be charged.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment to be duly executed as of the date first above
written.
MAINE PUBLIC SERVICE COMPANY
By: ________________________
Title: _____________________
THE BANK OF NEW YORK,
as Agent and Bank
By: _________________________
Title: ______________________
FLEET BANK OF MAINE
By: _________________________
Title: ______________________
EXHIBIT A
OPINIONS TO BE GIVEN
BY COUNSEL TO THE COMPANY
This exhibit sets forth the substance of the legal opinions
to be included in the opinion letter of Verrill & Dana, counsel
to Maine Public Service Company (the "Company"), to be delivered
pursuant to Section 2(a)(v) of Amendment No. 4, dated as of
March 28, 1997 (the "Amendment") to the Revolving Credit
Agreement dated as of October 8, 1987 among the Company, the
signatory Banks thereto and The Bank of New York, as Agent, as
amended (the "Agreement").
The opinion letter should be in the issuing firm's normal
form for opinions given in commercial transactions, subject only
to customary qualifications and assumptions. It should be dated
the date of issuance of the Bank Mortgage Bond and addressed to
(i) The Bank of New York, individually and as Agent, and (ii)
Fleet Bank of Maine.
Capitalized terms used in this exhibit which are not
otherwise defined herein should be understood to have the
respective meanings ascribed thereto in the Agreement and the
Amendment.
Opinions:
1. The Company is a corporation duly organized, validly
existing and in good standing under the laws of the State of
Maine and has all requisite corporate power and authority to hold
and operate its properties and conduct its business as and where
now conducted in the State of Maine and to enter into the
Amendment and the Supplemental Indenture and to issue the Bank
Mortgage Bond as contemplated therein.
2. The First Mortgage Indenture, including the Supplemental
Indenture, has been duly executed and delivered by the Company,
and the First Mortgage Indenture, as supplemented by the
Supplemental Indenture, constitutes a valid and legally binding
mortgage of the Company, enforceable against the Company in
accordance with its terms.
3. The execution, delivery and performance of the
Supplemental Indenture and the creation and issuance of the Bank
Mortgage Bond and compliance with the terms thereof have been
duly authorized by all necessary corporate action and do not and
will not violate any provision of law or, to the best knowledge
of such counsel, of any regulation, judgment, order, writ,
injunction, determination or award of any court, arbitrator or
governmental authority or of the Articles of Incorporation or By-
Laws of the Company and will not conflict with or result in a
breach of any of the terms, conditions or provisions of, or
constitute a default under, or result in the creation or
imposition of any mortgage, lien, charge or encumbrance (except
as contemplated by the First Mortgage Indenture, as supplemented
by the Supplemental Indenture) upon any of the property or assets
of the Company pursuant to the terms of, any indenture, mortgage,
deed of trust or other agreement or instrument to which the
Company or its property is bound.
4. The First Mortgage Indenture, as supplemented by the
Supplemental Indenture, creates a valid mortgage lien on the real
property, and a valid lien on the personal property, located in
the State of Maine described therein as subject to the lien
thereof, except as such property may have been released from the
lien thereof in accordance with the terms thereof.
5. The First Mortgage Indenture, including the
Supplemental Indenture, has been duly recorded as a mortgage on
real estate, and financing statements with respect thereto have
been filed, in each place in the State of Maine in which such
recording or filing is required to be made to perfect and
preserve the lien of, or security interest created by, the First
Mortgage Indenture; and no other recordation or filing or re-
recordation or re-filing thereof is necessary in order to
preserve and protect the lien of, or security interest created
by, the First Mortgage Indenture, and no taxes are payable to the
State of Maine or any subdivision thereof in connection with the
execution, authentication, issuance and delivery of the Bank
Mortgage Bond, or the mortgaging of property under the First
Mortgage Indenture.
6. The Bank Mortgage Bond is in due and proper form, has
been duly executed and delivered by the authorized officers of
the Company and authenticated by the Trustee, is the valid and
legally binding obligation of the Company, is enforceable in
accordance with its terms and entitled to the benefits and
security of the First Mortgage Indenture and the Supplemental
Indenture, and is secured to the same extent as, and on a parity
as to all of the trust estate with, all other bonds outstanding
under the First Mortgage Indenture.
7. The issuance of the Bank Mortgage Bond pursuant to the
First Mortgage Indenture and the Supplemental Indenture has been
duly authorized by the Maine Public Utilities Commission, and no
other authorization, filing, consent or approval of any public
regulatory body of the State of Maine is required in connection
with the issuance of the Bank Mortgage Bond or the execution or
delivery of the Supplemental Indenture or the Bank Mortgage Bond
by the Company.
8. No taxes which have not been paid are payable under the
laws of the State of Maine on the original issuance of the Bank
Mortgage Bond or the mortgaging of property in connection therewith.
Exhibit 99(o)
Order Approving Stipulation 1 Docket No. 97-830
STATE OF MAINE
PUBLIC UTILITIES COMMISSION Docket No. 97-830
January 30, 1998
MAINE PUBLIC SERVICE COMPANY ORDER APPROVING
Annual Increase Under Rate STIPULATION
Stabilization Plan
WELCH, Chairman; NUGENT and HUNT, Commissioners
I. SUMMARY
In this Order, we approve a Stipulation that resolves the
issues in the Maine Public Service Company (MPS) annual rate
change proceeding. By approving the Stipulation, we authorize a
3.9% rate increase to be implemented on February 1, 1998, resolve
the ratemaking treatment of some of the 1997 and 1998 Maine
Yankee-related costs, and establish a minimum rate increase of
3.1% for February 1, 1999.
II. BACKGROUND
On November 14, 1997, MPS filed materials in support of its
annual rate increase under its previously adopted rate
stabilization plan (RSP). See Order Approving Stipulation,
Docket No. 95-052 (Nov. 30, 1995). The RSP is a comprehensive
multi-year rate plan that contains, among other provisions,
specified annual rate changes, a sharing of earnings outside a
bandwidth, a sharing of Maine Yankee net replacement costs and
Wheelabrator-Sherman (W/S) purchased power savings (1), and
customer service and reliability standards. Specifically, the
RSP contains a specified February 1, 1998 increase of 2.75% (as
well as a 2.75% increase on February 1, 1999) subject to the
plan's sharing and customer service penalty provisions.
In its November 14 filing, MPS sought a February 1, 1998
(1) The RSP states that any savings from the renegotiation of the W/S
Purchase Power Agreement (PPA) will reduce specified deferrals that would
be recovered in rates beginning in 2000. In our recent Order that approved
the renegotiation of the W/S PPA, we stated that the savings would instead
be used to offset rates during the remainder of the rate plan. Order
Granting Certificate of Approval, Docket No. 97-727 (Jan. 15, 1998)
Order Approving Stipulation 2 Docket No. 97-830
increase of 7.59%, consisting of the 2.75% specified increase, a
2.2% increase for recoverable Maine Yankee replacement power
costs, and a 2.62% increase for earnings sharing. The Company
also indicated that it would be subject to a penalty of $28,000
for failure to meet one of the customer service standards. As
required, the filing included updated marginal costs for pricing
flexibility and short-term energy only (STEO) rates for small
power producers.
Additionally, the Company raised several other items to be
resolved in this proceeding:
- Maine Yankee refueling outage. During the 1997 outage,
Maine Yankee, in anticipation of restarting the plant,
incurred refueling outage expenses (approximately
$43 million); MPS's share of the expense is approximately
$2.1 million. Consistent with prior practice regarding
refueling outages, MPS sought to defer and amortize the
costs over 18 months (Maine Yankee's previous refueling
cycle). MPS began to amortize this amount in August,
1997 so that the unamortized balance on December 31, 1997
was approximately $1,458,000.
- Maine Yankee resleeving expenses. The RSP provides for
a 5-year amortization of the resleeving expenses incurred
in 1995 that would leave approximately $230,000 of these
expenses unamortized by the end of the rate plan. Rather
than including this amount as stranded costs, the Company
proposed a modification so it would amortize the entire
amount by the end of the rate plan.
- Maine Yankee Sharing. The RSP does not specifically
address the sharing of Maine Yankee replacement power
costs from October 1, 1998 to January 31, 2000 (the end
of the rate plan), because the last rate adjustment is
February 1, 1999, using an annual reporting period ending
September 30, 1998. The Company requested that the
Commission allow it to defer 50% of the net replacement
costs for subsequent recovery.
- Wheelabrator-Sherman Savings. MPS proposed that it use
the savings from the renegotiation of the W/S PPA to
partially off-set its 50% share of recoverable Maine
Yankee replacement power costs; savings during 1998 would
off-set replacement costs during the same period.
Order Approving Stipulation 3 Docket No. 97-830
On November 12, 1997, the Commission issued a Notice of Annual Review and
Opportunity for Intervention. The Public Advocate filed for and was granted
intervention. Both the Public Advocate and the Advisory Staff conducted
extensive discovery on the MPS filing. Subsequently, the Company, the Public
Advocate, and the Advisory Staff had numerous discussions regarding the
resolution of the issues raised by the filing. As a result of these
discussions, MPS filed, on January 16, 1998, a Stipulation signed by it and
the Public Advocate that resolves the issues in this proceeding.
III. DESCRIPTION OF STIPULATION
The Stipulation provides for a February 1, 1998 rate increase of
3.9%. This amount represents the 2.75% specified increase plus approximately
half of the recoverable Maine Yankee replacement costs during 1997 ($562,000).
The remaining $523,000 of the 1997 Maine Yankee costs is deferred and will be
recovered in rates as part of the February 1, 1999 rate change regardless of
any future prudence determination. The Company agrees to waive any rights
under the RSP to recover in rates all amounts associated with its 1997
earnings deficiency ($1,280,000) and to write-off against 1997 earnings all
of the unamortized Maine Yankee refueling outage expenses ($1,458,000).
As part of the agreement, the parties agreed that the specified
February 1, 1999 rate increase of 2.75% shall be reduced to 2.00%, resulting
in approximately $380,000 of revenue that MPS will not recover. The February
1, 1999 increase will, as stated above, include the remaining $523,000 of 1997
Maine Yankee replacement costs. As a result, the Stipulation provides for a
minimum increase of approximately 3.1% for February 1, 1999 with the
Commission's having the discretion to authorize a greater increase. The
Stipulation also states that the Company will be able to off-set its
recoverable 1998 net Maine Yankee replacement power costs up to the amount of
W/S savings, projected to be $2.5 million. This amount of replacement costs
will not be subject to disallowance as a result of any future prudence or
reasonableness findings regarding Maine Yankee. Additional replacement power
cost over those off-set by the W/S savings, estimated to be $900,000, will be
deferred but subject to a prudence disallowance. Finally, the Stipulation
provides for a suspension of the customer service penalty pending the mid-term
review of the RSP.
The Stipulation does not contain a provision modifying the
Order Approving Stipulation 4 Docket No. 97-830
recovery of 1995 Maine Yankee resleeving expenses. The amortization period
will therefore remain unchanged.
On January 21, 1998, the Commission held a hearing during which the
parties presented the Stipulation and responded to questions. At the hearing,
parties agreed that the Commission should approve the updated marginal costs
and STEO rates that accompanied the Company's initial November 13, 1997 filing.
No party or interested person spoke against the stipulation.
Order Approving Stipulation 5 Docket No. 97-830
IV. DISCUSSION
MPS's annual rate change filing is designed to be a summary
proceeding intended to implement the provisions of the RSP. This year's
filing, however, raises a difficult issue because it includes recovery of costs
related to the Maine Yankee shutdown. MPS has indicated that virtually all of
its requested 7.59% increase above the 2.75% specified amount in the RSP
results from Maine Yankee-related costs. The recent permanent shutdown of
Maine Yankee has raised issues regarding the reasonableness and prudence of
the plant's management over the last several years. Accordingly, the
Commission has opened an investigation of the matter, in part based on the
findings of a management audit of Maine Yankee (submitted August 29, 1997).
Notice of Investigation, Docket No. 97-781 (Oct. 24, 1997). To aid in this
Investigation, the Commission ordered a further management audit of Maine
Yankee; the results of this audit are expected in the near future. The
prudence of Maine Yankee management has also been raised at the FERC (Docket
Nos. ER98-570-000, EL98-14-000, EL98-15-000) (2). Because of the nature of the
prudence reviews, ultimate findings and ratemaking consequences cannot be
expected for at least several months.
To the extent that Maine Yankee's past actions were prudent, MPS is
entitled under the RSP to recover some of its Maine Yankee-related costs
through its February 1, 1998 rate increase. If imprudence is found, MPS may
not be entitled to recover some or all of these costs. These circumstances
create a dilemma in that, as a practical matter, the Commission can not
litigate Maine Yankee prudence in the context of MPS's annual review.
The Stipulation in this case presents a creative solution to
this dilemma. Essentially, the Stipulation resolves the Maine
Yankee costs issue by providing that MPS will not recover certain
costs to which it may be entitled, but will recover other costs
that, if imprudence is found, may have been disallowed. This is
accomplished by an agreement for a write-off of Maine Yankee
(2) In an Order issued on December 2, 1997, the Commission stayed its
Maine Yankee investigation pending a determination of the issues
at FERC; the Order did not stay the ongoing management audit.
Order Approving Stipulation 6 Docket No. 97-830
refueling expenses (3), a waiver of recovery of the 1997 earning sharing
amount, a reduction in the specified 1999 rate increase, and recovery of a
determined amount of 1997 and 1998 net replacement power costs. Amounts of
1998 net replacement power costs beyond the determined amount, as well as Maine
Yankee-related costs after 1998 (e.g. continued purchase of replacement power),
are subject to disallowance based on imprudence findings.
After careful consideration, we conclude that the Stipulation
represents an appropriate balance of regulatory litigation risk, the need to
moderate rate increases, and the uncertainty involving investigations of Maine
Yankee prudence. We note that, even if imprudence is found, MPS is likely to
recover some level of Maine Yankee-related costs; only the incremental costs
resulting from imprudence generally would be subject to disallowance. Thus,
the Stipulation provides a reasonable resolution of this proceeding.
Accordingly, we
O R D E R
1. That the Stipulation filed on January 20, 1998 is hereby approved and
incorporated into this Order;
2. That Maine Public Service Company is authorized to increase its rates
by 3.9% effective February 1, 1998;
3. That the updated marginal costs and short-term energy only rates
filed on November 14, 1997 are hereby approved.
Dated at Augusta, Maine this 30th day of January, 1998.
BY ORDER OF THE COMMISSION
(3) There is an issue whether MPS was entitled to amortize any costs as
a "refueling outage" during 1997. The same issue has been raised
in the pending Bangor Hydro-Electric Company rate case (Docket No.
97-116). If the amortization was improper, MPS would recover half
of the amortized amount through earning sharing (assuming prudence).
Order Approving Stipulation 7 Docket No. 97-830
_______________________________________
Dennis L. Keschl
Administrative Director
COMMISSIONERS VOTING FOR: Welch
Nugent
Hunt
Order Approving Stipulation 8 Docket No. 97-830
NOTICE OF RIGHTS TO REVIEW OR APPEAL
5 M.R.S.A. s. 9061 requires the Public Utilities Commission to give each
party to an adjudicatory proceeding written notice of the party's rights to
review or appeal of its decision made at the conclusion of the adjudicatory
proceeding. The methods of review or appeal of PUC decisions at the conclusion
of an adjudicatory proceeding are as follows:
1. Reconsideration of the Commission's Order may be requested under
Section 1004 of the Commission's Rules of Practice and Procedure
(65-407 C.M.R.110) within 20 days of the date of the Order by filing
a petition with the Commission stating the grounds upon which
reconsideration is sought.
2. Appeal of a final decision of the Commission may be taken to the Law
Court by filing, within 30 days of the date of the Order, a Notice of
Appeal with the Administrative Director of the Commission, pursuant
to 35-A M.R.S.A. s. 1320 (1)-(4) and the Maine Rules of Civil
Procedure, Rule 73 et seq.
3. Additional court review of constitutional issues or issues involving
the justness or reasonableness of rates may be had by the filing of
an appeal with the Law Court, pursuant to 35-A M.R.S.A. s. 1320 (5).
Note: The attachment of this Notice to a document does not indicate the
Commission's view that the particular document may be subject to
review or appeal. Similarly, the failure of the Commission to
attach a copy of this Notice to a document does not indicate the
Commission's view that the document is not subject to review or
appeal.
Exhibit 99(p)
MARKET POWER IN ELECTRICITY
a study of market power issues raised by the
prospect of retail competition in the electric industry
INTERIM REPORT
February 2, 1998
presented to the
Joint Standing Committee on Utilities and Energy
of the Maine Legislature
by the Department of the Attorney General
and the
Public Utilities Commission
pursuant to P.L. 1997 ch. 447 Part B
ANDREW KETTERER THOMAS L. WELCH
Attorney General PUC Chairman
STEPHEN L. WESSLER WILLIAM M. NUGENT
Director, Public Protection Unit Commissioner
FRANCIS ACKERMAN HEATHER F. HUNT
Assistant Attorney General Commissioner
STATE OF MAINE
PUBLIC UTILITIES COMMISSION
In Re Market Power Study ) Docket No. 97-877
)
INTERIM REPORT
I. INTRODUCTION
A. The Statute and the Study
Maine's restructuring statute, signed into law May 29, 1997,
is designed to promote effective competition in the market for
sale and generation of electricity in the State.{1} The statute
is grounded on the policy axiom that competitive markets provide
higher quality products and services at lower prices. Under the
new law, the State's electric power industry, long a bastion of
regulation, will embark upon retail competition. As of March 1,
2000, consumers will be able to select among competitive
generation providers and marketers. At the same time, recognizing
that a proliferation of power delivery systems (including wires,
poles etc.) remains impracticable, the statute preserves state
regulation of transmission and distribution ("t&d") services.
Some economists believe that the introduction of competition
to electric markets will result in enormous savings to consumers,
as well as benefits to the State's economy as a whole. Others
warn that the potential benefits of competition
1. P.L. 1997 ch. 316, much of which is codified at 35-A M.R.S.A.
Sections 3201-3217.
cannot be realized in wholesale and retail electric power markets in Maine
and New England unless these markets are structured at the outset
in such a way as to avoid control by a few large competitors.
Recognizing that the exercise of market power by a few large
companies poses a serious threat to these newly competitive
markets, the Legislature immediately followed its enactment of
the restructuring statute with passage of a law directing the
Department of the Attorney General ("Department") and the Public
Utilities Commission ("Commission") jointly to conduct a
comprehensive study of market power issues. A final report of the
Department's and Commission's findings and recommendations is due
December 1, 1998.{2}
The purpose of the required market power study is to
identify those aspects of the electric power market which may
frustrate the statutory goal of introducing effective competition
to Maine's electric markets. In conducting the study, therefore,
the Department and the Commission must assess the extent to which
the restructuring statute has accomplished its objectives, and,
wherever necessary, offer recommended corrections or
additions.{3}
2. P.L. 1997 ch. 447 Part B.
3. The Legislature directed that the study examine the effects of the
transition from cost-based to bid-based dispatch; the potential for horizontal
and vertical market power; the effect of imbalances of supply and demand; the
significance of transmission constraints and the ownership of transmission ties;
the significance of the isolation of portions of the grid from the New England
Power Pool grid; geographic market definition issues; and the scope of federal
jurisdiction. Id., section B-1. All of these issues receive preliminary
consideration in this interim report. In the final report, we plan to review,
in addition, approaches taken by other states to address market power issues.
-2-
The Legislature also directed that the Department and the
Commission provide a report of their preliminary findings and
recommendations as of February 1, 1998. The purpose of the
required preliminary assessment is to identify market power
issues which may require immediate legislative attention by the
Second Regular Session of the 118th Legislature, and cannot await
the final report.
This Interim Report responds to the Legislature's directive
in this regard. We begin by offering a working definition of
market power, and explain briefly why antitrust law has only
limited ability to remedy the problem. Then, in the sections
following, we turn first to a detailed assessment of vertical
market power issues affecting the retail market, then to a review
of horizontal market power issues in two wholesale markets: those
for energy generally, and for renewables (as defined in the statute).
We conclude that there is no area or issue which requires
legislative attention on an emergency basis. However, we identify
a number of issues which raise significant competitive concerns
and therefore merit further analysis and study. Additionally,
this preliminary report identifies competitive issues which the
Department and the Commission may address in the context of
regulatory or court proceedings. While no legislative
recommendations are offered at this time, we nevertheless discuss
options available to address the problems identified. We are
confident that further analysis will permit us to offer specific
recommendations in the context of our final report, due December
1, 1998.
-3-
B. Market Power and the Limits to Antitrust
Market power comes in two forms, horizontal and vertical.
Horizontal market power may be defined as the ability of a single
dominant firm or a group of dominant firms to profit by deviating
upward from competitive, marginal cost pricing (i.e., by charging
higher, or supracompetitive prices). The higher the market shares
of the individual firms, and the smaller the number of firms
competing in a market, the more that market will be subject to
the exercise of market power, and the less consumers will receive
the benefits of higher quality and lower price.
An illustration of this phenomenon is the British experience
of electric power deregulation. In Britain, a state-owned
industry was privatized, and split between only two firms. This
extraordinarily high concentration of market power led to higher
prices, and ultimately to the reimposition of regulation in the
form of price ceilings.
Vertical market power, in contrast, derives from a single
firm's integrated presence at more than one level of commerce.
For example, a firm which combines generation or retail marketing
of electric power with provision of t&d services is vertically
integrated. Vertical integration in itself is not necessarily
anticompetitive. Indeed, it is often efficient and beneficial to
consumers. However, where a vertically integrated firm is a
regulated monopolist at one level of commerce, it may possess the
ability to project its monopoly power to another level.
For example, an electric t&d company with a regulated monopoly
in a given service area might possess the ability to cross-subsidize
-4-
a retail marketing affiliate at ratepayers' expense by providing
services to the affiliate free of charge, or at subsidized prices.
This would enable the affiliate to compete unfairly in retail markets.
Such an exercise of vertical market power could deter other would-be
competitors from entering the market, and permit the vertically
integrated company to gain market power in the retail market.
The options available to antitrust enforcement agencies to
remedy vertical or horizontal market power in newly restructured
markets are limited and often inadequate. In essence, there are
only three opportunities for antitrust intervention. First, a
proposed merger or acquisition which significantly increases
horizontal concentration (and reduces competition) is subject to
effective challenge under state or federal antitrust laws.{4}
Second, collusive agreements or combinations among competitors
(e.g. price fixing) are illegal under antitrust law, and subject
to both criminal and civil enforcement.{5} Finally, exclusionary
conduct by a monopolist can be attacked as a monopolization
offense, though such cases are notoriously lengthy, cumbersome
and difficult to prove.{6}
It remains that preexisting market power, short of monopoly,
which is entrenched in the structure of the industry and
exercised unilaterally, is beyond the reach of antitrust. In view
of the limitations of antitrust enforcement, it is essential that
4. See 10 M.R.S.A. section 1102-A; 15 U.S.C. section 18. Vertical
mergers are also subject to challenge in certain circumstances.
5. See 10 M.R.S.A. section 1101; 15 U.S.C. section 1.
6. See 10 M.R.S.A. section 1102; 15 U.S.C. section 2.
-5-
Maine ensure, as far as the reach of its jurisdiction will allow,
that newly opened electric power markets are competitively
structured on day one. If the wholesale generation market or the
retail market embark on competition with highly concentrated structures,
or structures otherwise susceptible to the exercise of market power,
antitrust enforcers will have relatively limited remedial options,
and consumers may well pay supracompetitive prices.
II. EXECUTIVE SUMMARY
A. Introduction
Maine's restructuring statute is designed to promote competition in
electricity markets. Potential benefits to consumers in lower prices, however,
may not be achieved unless these markets are structured from the outset in such
a way as to avoid control by a few large competitors. Existing antitrust
remedies possess only limited effectiveness to address the problem of market
power.
The purpose of this study, mandated by the Legislature, is to assess the
extent to which electricity markets of which Maine forms a part are subject to
market power, and to make recommendations as to whether the restructuring
statute should be adjusted in light of that assessment. In this interim report
of our findings, we offer no specific legislative recommendations, but do
discuss the nature and extent of the problem of market power in relevant
markets, and review the available remedies, legislative and otherwise.
-6-
B. Vertical Market Power
Vertical integration of a regulated t&d monopoly with a marketer of
electricity results in market power which can find expression through unfair
cross-subsidization and favoritism. If allowed to proceed unchecked, these
practices could deter entry and result in market dominance by the monopoly
affiliate. This could harm Maine consumers in two ways: they would pay for the
regulated monopoly's cross-subsidization; and receive higher retail prices in
a concentrated market.
Two remedies are available: divestiture combined with a marketing ban;
and regulation. Maine's restructuring statute, while mandating divestiture of
generation, permits affiliate marketing subject to a code of conduct and, in
the case of CMP and BHE, a market share limitation. While acknowledging the
comprehensiveness of the statutory code of conduct, and the radical nature of
the market share limitation, we intend to analyse further the question whether
the regulatory solution adopted by the Legislature holds any benefit for
ratepayers which would justify preferring it over an outright ban on affiliate
marketing. A recommendation in this regard will be forthcoming in the final
report.
C. Horizontal Market Power: Wholesale Energy
Horizontal market power, defined as the ability of one or more dominant
firms to profit by deviating upward from competitive, marginal cost pricing,
can be gauged in terms of individual market shares and overall market
concentration, as measured by the Herfindahl-Hirschman Index. The relevant
product markets are wholesale energy and renewables as defined in the
restructuring statute. There are two primary relevant geographic markets: New
-7-
England (including southern and central Maine) and Aroostook County (which is
isolated from the New England grid). In addition, there may be a load pocket
indicating a separate geographic market in southern and central Maine in a
limited number of peak usage hours. Finally, the possibility that more
localised load pockets could develop merits analysis.
New England market. The New England market is highly
concentrated, indicating a significant degree of market power.
The primary repositories of market power are two southern New
England utilities, NU and USGen. Computer model simulations show
that NU and USGen possess sufficient market share to engage in
strategic behavior which would enable them to drive up spot
market prices by withholding capacity. Accordingly, horizontal
market power represents a serious threat in this market.
Remedial options are limited. The Department may have the
ability to advocate for divestiture in the context of antitrust
merger proceedings or regulatory proceedings before FERC.
However, state legislative influence is confined to the margin,
since wholesale electric rates, and the operation of wholesale
markets, are squarely within the exclusive jurisdiction of FERC.
To the extent that a load pocket exists in southern and central
Maine, the Commission already possesses statutory authority to
remedy market power within the load pocket, if necessary, by
imposing appropriate conditions on its approval of CMP's proposed
divestiture of generation assets. The advisability of statutory
adjustments relating to demand side management and transmission
enhancements will be analysed in the final report; in addition,
-8-
possible amendments to laws governing profiteering in necessities and unfair
trade practices will be considered.
Aroostook County market. The Aroostook County market is
also highly concentrated. Again, the Commission already possesses
the statutory authority to bring about some limited reduction in
this level of concentration by imposing conditions on its
approval of MPS' divestiture of generation assets. The Department
stands ready to review any proposed acquisition for antitrust
compliance. The final report will review, in light of
intervening developments, how best to prepare the Aroostook County market
for retail choice. The advisability of other legislative adjustments,
again including demand side management and transmission
enhancements, will also be considered.
D. Horizontal Market Power: Renewables
Maine's portfolio requirement that competitive electricity
providers demonstrate that 30% of their electricity supply
derives from renewable sources as defined in the statute
effectively creates a separate renewables product market. With
respect to southern and central Maine, the relevant geographic
market is New England; Aroostook County may also become a part of
the New England market if the Commission creates, by rule, a
market in tradeable renewable credits.
The New England renewables market is highly concentrated,
indicating a high degree of market power. The problem is especially
serious in this market in that competitors with high market shares in
renewables may possess the ability to deny other players entry to
Maine's energy markets generally. Existing remedies are limited.
-9-
The Commission possesses authority to address market power in
renewables by imposing appropriate conditions, if necessary, on
its approval of CMP's and MPS' proposed divestiture of generation
assets. The Department possesses antitrust authority to review
mergers.
Finally, this interim report suggests that the ability of
competitors with high renewables market shares to exclude others from
Maine energy markets generally could be addressed by regulatory or
legislative provision of a safety valve. For example, a competitor could
be accorded permission to make good a renewable deficit by paying it back
in a subsequent year, or by contributing to a fund for promotion of
renewables.
III. VERTICAL MARKET POWER ISSUES
A. Vertical Market Power
Vertical integration of a regulated t&d monopoly with an
affiliate which is a marketer of electricity (or a competitive
provider of generation) results in market power. In the absence
of a legislative or regulatory solution, this vertical market
power exhibits itself through unfair cross-subsidization of, and
favoritism in its dealings with, the affiliate. Linked by common
ownership and driven by the profit motive and their duty to
stockholders, the monopoly and its affiliate can be expected to
seek and exploit every lawful opportunity to collaborate for
their common advantage. Through unfair cross-subsidization and
favoritism, a vertically integrated company can deter would-be
competitors from entering the market, and seize a dominant market share.
-10-
This phenomenon can occur in various forms, of which the
direct provision of free or subsidized services by the monopoly
to its affiliate is only the most obvious. The regulated t&d
monopoly can also afford the affiliate access to strategic
information unavailable to competitors. Information regarding
customer loads, for example, would give the affiliate a distinct
competitive advantage.{7} Further, where the regulated monopoly
is also the incumbent utility, the affiliate may have the
opportunity to reap significant competitive advantage through the
use of the monopoly's name, which carries with it a reputation
for reliable service. The regulated monopoly can also provide its
affiliate with other valuable marketplace advantages -- for example,
the assurance that repairs will be performed first for the affiliate's
customers; that the t&d will steer new customers to the affiliate
rather than to competitors; or that other subtle preferences will
be accorded.
In the aggregate, these manifestations of vertical market
power represent a significant threat to the success of
restructured electric power markets. Simply put, the danger is
that if such market power is given free rein, it will deter new
competitors from entering the market, and unfairly disadvantage
those which do enter. This is an especially serious risk in Maine
which, as a small, largely rural market, may not offer potential
entrants the returns available elsewhere.{8} If power
7. Information regarding loads would enable the affiliate to target its
pricing to the circumstances of the particular customer. The restructuring
statute provides that "[u]pon request from a competitive electricity provider,
the commission shall provide load data on a class basis that is in the
possession of a transmission and distribution utility..." 35-A M.R.S.A. section
3203 (16).
8. Maine's advertising markets, generally speaking, are separate from
those of southern New England.
-11-
marketers conclude that incumbent utility affiliates can exert vertical
market power to seize the lion's share of the Maine market, they may well
conclude that the game is not worth playing. In that situation,
Maine consumers would pay twice: once as ratepayers to finance
the regulated monopoly's cross-subsidization practices; and a
second time in the higher prices that could be expected in a
concentrated market with a low level of competition.
B. Remedies
Two remedies are available to combat vertical market power:
divestiture and regulation. In its original proposal for Maine's
restructuring statute, the Commission recommended divestiture.
Ultimately, however, while requiring divestiture of generation
assets, the Legislature chose to permit limited retail marketing
by an affiliate of the t&d monopoly, subject to regulation.
Vertical divestiture which legally separates the regulated
t&d monopoly from generation and marketing functions eliminates
the problem of vertical market power. Deprived of retail
presence, the regulated t&d company would have no ability to reap
any retail advantage from its monopoly position. Divestiture
combined with a ban on marketing by the regulated monopoly thus
represents a complete and totally effective prophylactic solution
to the problem of vertical market power.
The regulatory alternative selected by the Legislature,
while requiring divestiture of generation assets, permits the
regulated monopoly to maintain a retail marketing presence
through an affiliate. The statute attempts to deal with the
-12-
problem of vertical market power in two ways: (1) by limiting the
largest vertically integrated marketers in the State (Central
Maine Power and Bangor Hydro-Electric Co.){9} to a one-third
market share in the regulated monopoly's service territory; and
(2) by subjecting CMP, BHE and the remaining vertically
integrated marketer, Maine Public Service Co.,{10} to a statutory
or regulatory code of conduct to be enforced by the Commission.{11}
The legislative choice of this regulatory response to
vertical market power raises three questions:
(1) Can enforcement of the statutory and regulatory codes
of conduct effectively prevent market power from being exercised?
(2) Will the one-third market share limitation applicable
to CMP and BHE sufficiently reduce the risk of deterring retail
entry into (or encouraging exit from) their service territories?
(3) What is the likely cost of the required regulatory
effort, and who should pay for it?{12}
9. Hereinafter "CMP" and "BHE" respectively.
10. Hereinafter "MPS".
11. 35-A M.R.S.A. sections 3205-3206.
12. The restructuring statute does require the Commission to report to the
Legislature annually (on December 31st of each calendar year) regarding its
"actual and estimated future costs of enforcing and implementing the provisions
of this chapter governing the relationship between a [t&d] utility and an
affiliated competitive electricity provider and the costs incurred by [t&d]
utilities in complying with those provisions." 35-A M.R.S.A. section 3217(1).
At the outset, the Commission's costs are chargeable to its general budget
funded by utility assessments, and ultimately to ratepayers.
-13-
In our view, each of these questions requires further
analysis prior to implementation of the legislation. We are
preparing to conduct such analysis, and make any needed
recommendations for legislation addressing this issue, in our
final report. In the present context, we offer the following
comments, which will shed some light on the nature of the
questions we propose to examine.
C. Codes of Conduct
The code of conduct enacted by the Legislature for
application to CMP and BHE appears to be a fairly comprehensive
effort to police the vertical relationship between a t&d company
and its affiliated retail marketer.{13} Particularly noteworthy
is the ban on joint advertising. While there may well be areas
in which improvements are possible, the larger issue deserving of
attention in the final report is whether any code of conduct can
effectively prevent the exercise of vertical market power.
The problem is not a new one. Vertical market power and
cross-subsidization were the crux of the historic monopolization
case brought by the U.S. Department of Justice against AT&T. The
government, in seeking divestiture in that case rather than a
court-ordered code of conduct, clearly subscribed to the belief
that a code of conduct ultimately would be ineffective to achieve
its purpose. In approving the 1982 settlement, the court agreed:
AT&T's pattern during the last thirty years
has been to shift from one anticompetitive
13. The statutory code of conduct applies only to CMP and BHE, but could
form the basis for a regulatory code to be applied to MPS.
-14-
action to another, as various alternatives
were foreclosed through the action of
regulators or the courts or as a result of
technological development. In view of this
background, it is unlikely that, realistically,
any injunction [in essence a code of conduct]
could be crafted that would be both
sufficiently detailed to ban specific
anticompetitive conduct yet sufficiently
broad to prevent the various conceivable
kinds of anticompetitive conduct that AT&T
might employ in the future.
United States v. AT&T, 552 F. Supp. 131, 167 (D.D.C. 1982).
Thus, the Court preferred the "surer, cleaner remedy of
divestiture". Id., 168 fn. 155.
AT&T did not have a monopoly on corporate ingenuity. It is
only to be expected that incumbent electric utilities, too, will
explore every lawful avenue to devise new ways to derive market
advantage from vertical integration. There inevitably will be a
difference in perspective between utilities and regulators as to
what costs are properly chargeable to ratepayers.
A recent audit performed for the California Public Utilities
Commission Office of Ratepayer Advocates, for example, found that
over a two-year period, Pacific Gas & Electric Company ("PG&E"),
an incumbent utility with a regulated t&d monopoly, applied $33.7
million of ratepayers' money to subsidize competitive affiliates.
In a 1000-page report, the auditors found a catalog of vertical
abuses, including overbilling of the regulated monopoly by an
affiliate, underbilling by the monopoly to another affiliate, and
-15-
provision of free services by the monopoly or its affiliates.{14}
Like the AT&T court, we have greater confidence in the
profit-driven ingenuity of a corporation answerable to its
stockholders than we do in the ability of legislators or
regulators to bar by regulation every conceivable avenue for the
exercise of vertical market power, and then effectively police
the boundaries thus established. For this reason, our tendency
will be to review the efficiency of the proposed regulatory
solution with a skeptical eye.
D. The Market Share Limitation
Turning to the second question, it is clear that the
statutory provision limiting CMP and BHE to a one-third market
share in their service territories is a radical measure which to
some extent will mitigate the exercise of vertical market
power.{15} Potential entrants which are skeptical (as we are)
concerning the efficiency of codes of conduct can therefore
derive some amount of reassurance from the market share
limitation. On the other hand, the concession of a third of the
market as fair game for the incumbent utility may still dampen
the enthusiasm with which potential and actual entrants regard
Maine. In sum, the market share provision limits the
potential deterrent to competition of allowing affiliate
marketing -- but that may not be enough.
14. San Jose Mercury News, Dec. 4, 1997.
15. The market share limitation does not apply to MPS. Whether it should
so apply is a question we defer to the final report.
-16-
We question whether Maine, a small, largely rural state, can
afford to dampen the enthusiasm of potential entrants to any
degree. It is not clear to us that the regulatory solution
adopted by the Legislature holds any benefit for ratepayers, or
for the Maine economy as a whole, which would justify preferring
it over the "surer, cleaner remedy" of a ban on affiliate
marketing. We will continue to study this issue and will offer
recommendations in our final report.
E. The Cost of Regulation
It appears, indeed, that under the present legislative
scheme, the costs of the regulatory effort required to police the
vertical boundary will add to the burden borne by ratepayers. It
is unclear how important these costs are likely to be. Again,
however, the justification for imposing any such costs on Maine's
ratepayers is far from self-evident. It is the affiliate marketer
and its stockholders which stand to gain from its participation
in retail marketing, not ratepayers. Our tendency, therefore, is
to inquire why these costs should not be borne by marketing
affiliates and their stockholders, rather than by ratepayers,
from the outset.
F. Recommendation
No legislative correction or addition is recommended at this
time. However, further analysis will focus on questions regarding
(a) the efficacy of codes of conduct; (b) the impact of the
market share limitation; and (c) the importance of the regulatory
costs which will be incurred in policing the vertical boundary
under the restructuring statute as written, and how such costs
should be defrayed. In particular, we plan to conduct a thorough
survey of the approaches adopted by other states in
-17-
addressing these problems; and to canvas legal and academic literature
more comprehensively than has been possible to date. We also plan to
solicit and take account of the views of stakeholders concerning
these matters. On the basis of such further analysis, we expect
to offer a recommendation in our final report as to whether the
Legislature should reconsider the regulatory approach to vertical
market power reflected in the statute.
IV. HORIZONTAL MARKET POWER: WHOLESALE ENERGY
We have defined horizontal market power as the ability of a
single dominant firm or group of dominant firms to profit by
deviating upward from competitive, marginal cost pricing. The
larger a single firm's market share, and the fewer the number of
firms competing in the market, the greater will be the ability of
the dominant single firm or group to exercise market power.
Accordingly, the extent to which a market is subject to
horizontal market power can be gauged in terms of the market
shares of individual firms, or in terms of overall market
concentration.
The first step in assessing levels of market concentration
is to define the wholesale electric market in terms of products
and geography.
A. Market Definition
For purposes of the evaluation of horizontal market power offered here,
the most important relevant product markets are wholesale energy, including
-18-
renewables (the focus of this section) and renewables separately (to which we
turn in the following section).{16}
Defining relevant geographic markets is more problematic.
In the electric power industry, the perimeter of the geographic
market depends upon the extent to which transmission ties permit
imports into a region, or to which transmission constraints or
bottlenecks limit sales of power within a region. There appears
to be general agreement that the wholesale generation market of
which southern and central Maine forms a part is, broadly
speaking, defined by the New England Power Pool ("NEPOOL") grid,
which covers most of the six-state region (with the sole
exception of Maine's Aroostook County).{17}
However, rather than simply accepting this hypothesis as
fact, we are examining the contrary possibility that southern and
central Maine may be geographically isolated as a result of
constraints which limit imports of power into the State from
southern New England and from New Brunswick. If Maine's peak
load exceeds the transmission capacity of ties to out-of-state
generation sources, the result will be that some in-state
generation facilities would be required to run in
16. In fact, there are numerous relevant product markets. In addition to
energy, installed capability, Ten Minute Spinning Reserve, Ten Minute
Nonspinning Reserve, 30-minute Operating Reserve, Automatic Generation Control
and Operable Capability will all be the subject of transactions on the New
England power exchange. While energy is clearly the most important of these for
purposes of this analysis, we will assess whether there may be market power
problems peculiar to any other electric power product market in the final
report.
17. See generally New England Power Pool, Market Power Study, FERC Docket
Nos. OA-237-000 and ER 97-1079-000, Prepared Direct Testimony of William H.
Hieronymus, e.g. at 19; New England Power Co., FERC Docket Nos. ER-98-6-000 and
EC-98-1-000, Market Power Analysis: Affidavit and Workpapers of Dr. Joe D.
Pace, e.g. at paragraph 34. We do not necessarily agree that the relevant
geographic market is as broad as NEPOOL for all purposes.
-19-
some hours in order to meet demand. The owners of such "must-run" facilities
within the State might then possess horizontal market power in
peak hours when their facilities were the only source of energy
available. In this scenario, southern and central Maine would
become a "load pocket", and would constitute the relevant
geographic market in which to assess market power in affected
hours.{18}
There is no question that Aroostook County, isolated from
the NEPOOL grid, represents a geographic market separate and
apart from southern and central Maine, and from New England.{19}
While power emanating from southern Maine and other New England
states can reach Aroostook County by using the MEPCO transmission
line running through New Brunswick, firm energy transactions over
this line are not possible due to minimum tie flow requirements
from New Brunswick to New England. Accordingly, New England power
generators cannot be treated as a source of supply for Aroostook
County.
In the sections below, therefore, we examine concentration
in the New England market, and available remedies, before
returning to address the possibility that market power may also
require remediation in the context of a southern and central
18. Similarly, there may be other load pockets, affecting varying numbers
of hours, elsewhere in New England. For example, Boston appears to be a load
pocket.
19. To the extent it is definable solely in terms of the flow of
electricity, the geographic market of which Aroostook County forms a part should
be viewed as including New Brunswick, Nova Scotia and perhaps other sections of
eastern Canada as well. However, Canadian utilities are not subject to the
restructuring initiatives undertaken by FERC or this State. Accordingly,
Aroostook County (at least initially) will be the only section of this eastern
Canadian grid which is open to wholesale and retail competition. For this
reason, it seems appropriate to analyse Aroostook County as a separate
geographic market.
-20-
Maine load pocket. Finally, we assess concentration in the
Aroostook County market, and remedial options there.
B. Herfindahl-Hirschman Index
Federal and state antitrust agencies (including the
Department) employ the Herfindahl-Hirschman Index (HHI) to
measure market concentration.{20} The HHI is arrived at by
squaring the market shares of all the competitors in a given
market. This simple mathematical device expresses the insight
that market power increases exponentially in proportion to market
share. Federal antitrust guidelines used by the Department in
merger enforcement indicate that a market with an HHI of 1000 or
less should be viewed as unconcentrated (and therefore likely to
function competitively).{21} A market with an HHI between 1000
and 1800 is described as moderately concentrated; while any HHI
over 1800 is termed highly concentrated.{22} A market in the highly
concentrated category is subject to a high degree of market power.
D. Concentration in the New England Market
Even if a south-central Maine load pocket exists in some
small number of hours, New England remains, for most purposes,
the relevant geographic market in which to assess horizontal
market power in the wholesale generation market. Here again,
20. Horizontal Merger Guidelines, 57 Fed. Reg. 41552 (1992).
21. For example, ten firms with market shares of 10% each would yield an
HHI of 1000 (10 squared x 10).
22. For example, a market comprising five firms with market shares of 20%
each would yield an HHI of 2000 (20 squared x 5).
-21-
there is no significant disagreement that the market is highly
concentrated, with an HHI in the 1800- 2000 range.{23}
A rough approximation of an HHI calculation for the New
England generation market follows (using installed generation
capacity):
Market share HHI
Northeast Utilities ("NU") -- 35% 1225
USGen New England ("USGen") -- 20% 400
Sithe Energies, Inc. ("Sithe") -- 13% 169
CMP{24} -- 7% 49
United Illuminating -- 5% 25
Others {25} -- 20% 32
100% 1900
23. In the context of its application to FERC for authorization to charge
market-based rates, NEPOOL presented a market power analysis conducted by Dr.
William Hieronymus which shows that, when it is assumed that market participants
have no load responsibilities, HHIs for relevant products range from
approximately 1700 to approximately 2000. When it is assumed that market
participants have load responsibilities under a state regulatory regime, the HHI
results are significantly lower. New England Power Pool Market Power Study,
FERC Docket Nos. OA97-237-000 & ER97-1079-000, Feb. 28, 1997, Prepared Direct
Testimony of William H. Hieronymus, see e.g. Exhibits WHH-12 - WHH-13. Similar
results were obtained in the market power analysis conducted by Dr. Joe Pace on
behalf of USGen for purposes of that company's separate application to FERC for
market-based rate authority. New England Power Company, FERC Docket Nos. EC98-
1-000 & ER98-6-000, 2 Affidavit of Dr. Joe D. Pace, Attachment 2. While some
incumbent utilities with elevated market shares, such as NU, continue to have
load responsibilities which may mitigate market power to some extent in the
short term, our task in this report is to assess the structural readiness of
electric power markets for competition across the board. Accordingly, the
short-term mitigating effect of load responsibilities is discounted.
24. The percentage shown reflects CMP's market share prior to its proposed
asset sale.
25. The remaining 20% is split between numerous market participants.
There is some disagreement as to the level of importance which should be
accorded to imports from New York and New Brunswick.
-22-
These figures suggest that the New England market will be subject
to some significant degree of market power, and that the primary
repositories of that market power will be two southern New
England utilities, namely, NU and USGen.{26}
However, the calculation of an HHI is the starting-point,
rather than the conclusion of the analysis. Under federal merger
guidelines, antitrust enforcement agencies look beyond HHI
numbers to consider a number of other factors in assessing the
impact of a proposed merger or acquisition.
Primary among these other factors is ease of entry. The holders of market
power in a concentrated market will find themselves unable to wield that power
to raise price above competitive levels if new entry into the market is
relatively easy. However, federal guidelines consider entry sufficiently easy
to constrain the exercise of market power only if entry could be accomplished
within two years. In spite of changes in available technology, we doubt that
entry into the New England wholesale generation market can be effected on a
two-year schedule.{27} This suggests
26. USGen is a subsidiary of PG&E.
27. See Wisconsin Electric Power Company, 79 FERC paragraph 61158 at
61695-61696 (recorded in merger case established that need for lengthy
regulatory approvals and length of time between planning and completion of new
generation would prevent new entrants from mitigating acquirer's market power
in timely fashion; noting "significant barriers to timely market entry");
Electric Power Research Institute, Technical Assessment Guide Vol. 1:
Electricity Supply - 1993 (Revision 7), June 1993, Exhibit 23 (preconstruction,
license and design time for new generation is two years; construction time is
a further two years).
-23-
that the market power of NU and USGen may not be adequately constrained by the
prospect of new entry, at least in the short-term.{28}
E. Modelling the New England Market
In addition to applying a standard merger analysis, we rely
for purposes of this interim report on the only simulation
modelling of the New England market of which we are aware. The
model to which we refer was developed by Synapse Energy
Economics, Inc.{29} Using detailed data input regarding hourly
customer loads, capacity and operating costs for generating units
and transmission tie capacity into New England, the Synapse model
simulates "strategic behavior" by market participants.
Specifically, the model tests the theory that players with
significant market share will be in a position to "game" the New
England spot market by withholding capacity, thereby increasing
the market-clearing price received by all participants.
The New England spot market, to be operated by an
"independent system operator" ("ISO") recently established by the
Federal Energy Regulatory Commission ("FERC"), will function as
the principal price-setting mechanism for energy in New England.
Participants will bid power into the spot market 24 hours in advance, with
28. We are aware that a significant level of merchant plant development
activity has been announced in New England. Also noteworthy, however, is the
fact that a significant share of this new development is being undertaken by
USGen. See e.g. New England Power Company, FERC Docket Nos. EC98-1-000 & ER98-
6-000, 1 Affidavit of Dr. Joe D. Pace, paragraphs 23, 28, 30; 4 Pace Affid. 209-
210, 214, 218-219. New capacity which is disproportionately in the hands of
market leaders could serve to exacerbate market power problems.
29. Bruce Biewald of Synapse has been retained by the Department and the
Commission as their consultant for purposes of this study.
-24-
a separate bid for each generation facility for each hour. The market will
clear each hour at the price bid for the last generation facility required to
meet demand in that hour. In peak hours, and indeed in a significant portion
of nonpeak hours as well, market participants with multiple facilities will
have the ability to drive up the market-clearing price by bidding so high on
a particular facility as to effectively withhold that facility's capacity from
the market.
The results obtained by Synapse show that in fact, NU and
USGen could both profit handsomely from such strategic behavior
at the expense of New England consumers. Specifically, Synapse
concludes that through economic withholding of capacity, NU could
increase prices to New England consumers by $823 million, or
approximately 30% over a one-year period; while USGen could
similarly raise prices by $77 million or 6.4%. If all four
leading participants in the market engaged in such behavior, the
additional cost to consumers would be $891 million, representing
an increase of 32.1%.{30}
These results demonstrate that horizontal market power poses
a serious threat to competition in the wholesale New England
electric power market. However, the ability of the Maine
Legislature to take remedial action to protect competition in
this sphere is limited to the margin. This is because wholesale
30. B. Biewald, D. White & W. Steinhurst, Horizontal Market Power in New
England Electricity Markets: Simulation Results and a Review of NEPOOL's
Analysis. While these results have been criticized in the context of the
pending NEPOOL market-based rate application at FERC, Mr. Biewald stands by them
in a recent affidavit, adding some new modelling runs which underscore the fact
that the New England wholesale market is susceptible to market power abuses in
a high percentage of nonpeak, as well as peak hours. New England Power Pool,
FERC Docket Nos. OA-97-237-000 and ER-97-1079-000, Testimony of Bruce Edward
Biewald on behalf of the Maine Attorney General, Jan. 23, 1998.
-25-
electric power rates, and the operation of wholesale electric
power markets, are squarely within the exclusive jurisdiction of
federal authorities, viz., FERC.{31} With this in mind, we
review available remedial options below.
F. Remedies: Divestiture
The most obvious solution to the problem of market power in
New England would be to require divestiture of some substantial
portion of the generation facilities held by market leaders NU
and USGen.{32} Maine's ability to achieve this outcome, however,
is limited.
Maine cannot require divestiture of NU generation facilities
by state legislation. Indeed, absent new federal legislation,
even FERC lacks authority to order divestiture directly.{33}
However, it is possible that at some future time, perhaps as part
of restructuring undertaken by Connecticut authorities, NU will
voluntarily divest generation facilities. FERC will have
approval authority over proposed transactions (and related
market-based rate applications) in this regard. The Department
and other state Attorneys General and Public Advocates will have
31. See e.g. Maine Yankee Atomic Power Company v. Public Utilities
Commission, 581 A. 2d 799, 804 (Me. 1990) (Commission had no authority to
require reduction in generator's wholesale rate, set exclusively by FERC;
attempt to do so was preempted).
32. Requiring the fracturing of Sithe and CMP market shares might also be
beneficial, but would be less important in proportion to their smaller market
shares, unless these entities possess market power within a load pocket in a
significant number of hours.
33. FERC does, however, possess the ability to require divestiture as a
condition of a grant of market-based rate authority, as we discuss below.
-26-
the ability to intervene before FERC to advocate that NU's block
of generation facilities be divested piecemeal, rather than in a
unitary sale to a single buyer.
In addition, the Department could, in an appropriate case,
file litigation under federal merger law to impose divestiture
conditions on any proposed transaction. Such litigation would be
more likely to succeed, however, if the proposed acquirer had a
preacquisition presence in the New England market. Consequently,
if NU were to sell to a single out-of-market acquiring party, an
antitrust merger enforcement action would be less likely to
prevail.
In the case of USGen and Sithe, a different situation
obtains. USGen recently acquired most of its New England
generation facilities from the New England Electric System
("NEES"); Sithe has announced its intention to acquire most of
the generation capacity of Boston Edison Company. Both companies
are currently seeking approval of these acquisitions in pending
proceedings at FERC. The Department has intervened in the
pending USGen FERC proceeding, and is considering intervention in
the Sithe proceeding. In addition, the Department is currently
evaluating enforcement options under federal merger law.
G. Remedies: Mitigation and Market-Based Rates
As we have indicated, divestiture is clearly the most
effective remedy to horizontal market power in the New England
market, to the extent divestiture can be brought to bear.
However, there is another remedy which is available and is being
pursued.
-27-
In the context of federal restructuring of wholesale
electric power markets, FERC possesses authority to grant or deny
market participants' applications to charge market-based (as
opposed to regulated, cost-based) rates. In order to obtain such
authorization, market participants must show that they do not
possess market power in the relevant market, or that market power
has been mitigated.{34}
NEPOOL, of which NU, USGen, Sithe and CMP are all members,
has applied to FERC for market-based rate authority. The
application is currently pending. The Department is an
intervenor in this proceeding; an umbrella organization of which
the Commission is a member, the New England Conference of Public
Utilities Commissions ("NECPUC") has also intervened.{35}
NEPOOL, having initially argued that none of its participants
possessed market power except to a limited extent in
transmission-constrained conditions, has now proposed a
comprehensive market power mitigation plan supposedly designed to
remedy precisely the type of strategic behavior modelled by
Synapse.
The NEPOOL mitigation plan, if approved by FERC, would
empower the ISO to respond to economic withholding tactics by
various means, including imposition of default pricing or
limitations on a participant's bid flexibility. While the
Commission, as a member of NECPUC, has indicated conditional
approval of NEPOOL's mitigation plan, the Department takes the
position that the plan is inadequate. In a recent filing, the
Department contends that adequate mitigation must include a
34. See e.g., New York State Gas & Electric Corporation, 78 FERC paragraph
61309 at 62326 (1997).
35. Maine's Office of the Public Advocate is also an intervenor in this
docket.
-28-
structural remedy, namely, appropriate divestitures by NU, USGen
and perhaps Sithe as well, as a condition of full market-based
rate authority.{36}
H. Remedies: The Load Pocket Issue
Our analysis of the possibility that southern and central
Maine may constitute a "load pocket" is not yet complete. The
information gathered to date is insufficient to eliminate the
possibility that the aggregate capacity of transmission ties
linking Maine to southern New England and New Brunswick may be
marginally insufficient to meet Maine's peak load power needs in
a relatively small number of peak hours.
At this juncture, therefore, we cannot exclude the
possibility that Maine may be a "load pocket" in these peak
hours. We plan to continue gathering information on this
question. If there is a Maine load pocket, southern and central
Maine would become a relevant market in which to assess market
power during affected hours. Currently, a very high proportion
of the generating assets in this area are owned by CMP, making
this a very highly concentrated market, subject to a high degree
of market power.
However, the Legislature has already required that CMP
divest virtually all its generation assets, and CMP has recently
announced a sale of the bulk of those assets to FPL Group
("FPL"). Under the restructuring statute, CMP must seek Commission approval
of the sale. Ultimately, we believe that the Commission possesses authority
36. New England Power Pool, Docket Nos. OA-97-237-000 and ER-97-1079-000,
Comments of the Maine Attorney General on the NEPOOL Market Monitoring,
Reporting and Market Power Mitigation Proposal Dated December 19, 1997, filed
January 23, 1998.
-29-
to disapprove, or place conditions upon the proposed transaction on market
power grounds.
In addition, the mitigation plan proposed by NEPOOL, to be
administered by the ISO, to some extent may address market power
in the load pocket context. Specifically, the mechanisms used to
address an episode of economic withholding in a load pocket
result in "nonlocational" or "socialised" mitigation pricing.
This means, in essence, that the price increase caused by an
exercise of market power which might otherwise have resulted only
within the load pocket (in this instance Maine) would be averaged
out and absorbed across the entire New England region. These
mechanisms thus provide a partial cushion against the impact
which an exercise of market power might otherwise have on
consumers within the Maine load pocket.{37}
However, NEPOOL's nonlocational pricing scheme is controversial, and may
not remain in place for very long. Moreover, there are another scenarios which
we have not yet fully analysed: the possibility that the purported Maine load
pocket could become more significant (encompassing more hours) over time, or
that other, more localised load pockets could develop. In our final report, we
will consider whether, in order to provide to the extent possible for these
eventualities, limited legislative adjustments might be appropriate. In
particular, we plan to analyse the advisability of adjustments relating to
demand side management, and transmission
37. At the same time, nonlocational pricing means that Maine consumers pay
a share of price increases which flow from load pockets elsewhere in the region,
e.g. Boston. Even if Maine is a load pocket, therefore, locational pricing is
probably, on balance, in the interest of Maine consumers.
-30-
enhancements. In addition, we will consider whether any amendment to laws
governing profiteering and unfair trade practices may be in order.{38}
I. Concentration in the Aroostook County Market
Approximately half of the generating capacity which is
locally available to serve Aroostook County load is currently
owned by or contracted to Maine Public Service Company ("MPS").
The balance is divided between two wood-fired generators,
currently owned by CMP and Alternative Energy, Inc. ("AEI").{39}
The restructuring statute requires both MPS and CMP to divest
generation assets; again, the required asset sales are subject to
Commission approval.
It is noteworthy that MPS is not required to divest its
Tinker Generating Station and associated assets located across
the international frontier in Aroostook Junction, New
Brunswick.{40} These hydroelectric facilities comprise more than
half of MPS' generating assets. Although not required to divest
the Tinker assets, MPS has included them as part of its auction
package. The sale of the Tinker assets is subject to Commission
approval under 35-A M.R.S.A. section 3508.
In addition to local generating capacity, Canadian power will be available
to serve Aroostook County load. Indeed, under normal circumstances, the
38. See 5 M.R.S.A. section 207; 10 M.R.S.A. section 1105.
39. Locally available generating capacity includes MPS' hydro (primarily
Tinker Station), 35.8 MW; MPS' operable diesel capacity, 12.2 MW; Wheelabrator
Sherman wood cogeneration (contracted to MPS), 18.1 MW; and the FPL and AEI
wood-fired generators, 32 and 37 MW respectively.
40. The statute does, however, require MPS to divest its rights to the
Tinker capacity and energy. 35-A M.R.S.A. section 3204 (1) & (4).
-31-
capacity of transmission ties to New Brunswick would permit the entire Aroostook
County load to be served from Canada. It would appear that there are three
potential sources of Canadian power to compete with local generators: New
Brunswick Power ("NBPC"), Hydro Quebec ("HQ") and Nova Scotia Power ("NSP").{41}
However, in order to obtain access to the small Aroostook County market, HQ and
NSP must wheel their power across the service territory of NBPC. For this
privilege, they must pay a significant wheeling fee to NBPC. NBPC apparently
possesses the unilateral ability to increase the wheeling fee.{42} Accordingly,
NBPC can determine the price at which not only its own power, but also that
emanating from HQ and NSP, is available to consumers in Aroostook County. NBPC
may also have the ability to prevent HQ and NSP power from reaching the
Aroostook County market at all.{43} In these circumstances, HQ and NSP cannot
be viewed as effective competitors in their own right.
Following the MPS and CMP divestiture auctions which are currently in
progress, therefore, it appears that the competing suppliers of wholesale power
to Aroostook County will be few: NBPC and two or three acquiring parties. If
41. HQ holds an existing contract to supply MPS, and is active as a
marketer in the United States generally; NSP, on the other hand, hitherto has
shown little interest in selling power outside its own system.
42. NBPC house counsel indicates that wheeling fees are the subject of an
informational filing with New Brunswick authorities, but do not require their
approval; and that there is no Canadian federal approval process.
43. An outright denial of wheeling services might be subject to challenge
on a monopolization theory.
-32-
it comprises only three or four competitors, such a market would fall into the
highly concentrated category under federal guidelines, and would be subject to
a high degree of market power.
The Legislature has provided a corrective mechanism: as
noted above, the proposed MPS asset sale is subject to Commission
approval. By imposing conditions designed to alleviate market
concentration, the Commission can positively influence (albeit to
a limited extent){44} the level of competition in the Aroostook
County market.
The availability of other remedies bears further analysis.
For example, in the event of a proposal by an in-market acquirer
to purchase any part of the MPS assets, the Department would
subject the transaction to a careful review for compliance with
federal and state merger law. In addition, for purposes of the
final report, we plan to evaluate several possible legislative
adjustments. Again, these would include demand side management
and transmission enhancements.{45}
We also plan to consider all aspects of the question how best to prepare
Aroostook County for retail choice. Our current assessment is that retail
choice could subject Aroostook County consumers to a high degree of market power
dominance by NBPC.
44. Our analysis suggests that by imposing appropriate conditions, the
Commission may have the ability to reduce an extremely concentrated market, in
the range of a 3400 HHI, by approximately 300 points. Thus, even with such
conditions, the market would remain extremely concentrated.
45. The Commission is conducting a separate study of the feasibility of
connecting Aroostook County to the New England grid. 35-A M.R.S.A. section
3206(3).
-33-
J. Recommendations
No legislative correction or addition is recommended at this
time. The Department will pursue various regulatory enforcement
options, as described above, including interventions at FERC and
in other regulatory forums. The Department will also continue to
offer advice to the Commission on market power matters, in the
context of pending divestiture proceedings and in upcoming
rulemakings. The Commission is in any event cognizant of its
responsibility under the restructuring statute to employ its
approval power over divestiture proposals to ensure a reasonably
competitive market structure. In addition, the Department will
continue to evaluate proposed acquisitions and mergers in the New
England region for antitrust compliance.
Finally, the Department and the Commission will continue to
study the limited further remedial options which may be
legislatively available to protect or enhance competition. Such
options could include, for example, initiatives in the area of
demand side management and transmission enhancement, or
adjustments to the law governing unfair trade practices and
profiteering.
Special circumstances in Aroostook County indicate that it
may be subject to a high degree of market power. Accordingly, the
question how best to prepare this market for retail choice merits
further consideration in the final report in light of intervening
developments.
-34-
V. HORIZONTAL MARKET POWER: RENEWABLES
Maine's restructuring statute requires that, as a condition
of licensing, competitive electricity providers demonstrate that
no less than 30% of their portfolio of supply sources for retail
electricity sales in the State are accounted for by renewable
resources as defined in the statute.{46} This requirement results
in the statutory creation of a separate product market which, in
its turn, must be analysed separately for the presence of market
power.
A. Market Definition
In addition to addressing allowable fuel or energy types
used to produce renewable power, the statutory definition
specifies that in order to qualify, the power produced must be
capable of physical delivery "to the control region in which
[NEPOOL], or its successor as approved by the [FERC] has
authority over transmission". Accordingly, with respect to
southern and central Maine, the relevant geographic market in
which to analyse market power in renewables is the NEPOOL grid,
i.e., New England exclusive of Aroostook County.{47}
46. The statute defines renewable resource as "a source of electrical
generation that generates power that can physically be delivered to the control
region in which [NEPOOL], or its successor as approved by [FERC] has authority
and that .. [q]ualifies as a small power production facility under [FERC] rules
... whose total power production capacity does not exceed 100 megawatts and that
relies on one or more of the following: ... [f]uel cells; ... [t]idal power; ...
[s]olar arrays and installation; ... [w]ind power installations; ...
[g]eothermal installations; ... [h]ydroelectric generators; ... [b]iomass
generators; ...[g]enerators fueled by municipal solid waste in conjunction with
recycling." 35-A M.R.S.A. section 3210.
47. Because the statutory definition makes clear that renewable electrons
need only be delivered to the NEPOOL grid in order to qualify, and need not be
physically deliverable to Maine, it is irrelevant whether or not there is a load
pocket, for purposes of this portion of the analysis. In any event, as we note
above, it appears that if a load pocket exists in southern and central Maine at
all, it does so only in a relatively few hours.
-35-
The configuration of transmission ties, all other things
being equal, makes Aroostook County a separate market for
renewables, as for energy.{48} In the sections following, we
evaluate levels of concentration in both the New England and
Aroostook County renewables markets, before turning to a
consideration of remedial options.
B. Concentration in New England and Aroostook Renewables Markets
Our preliminary analysis indicates that the New England
market for renewables as defined in the statute is in the upper
range of moderate concentration. In the wake of CMP's proposed
divestiture, four participants hold approximately 75% of
renewable capacity, resulting in an HHI in the area of 1750.
Mkt share HHI
HQ -- 28% 784
NU -- 24% 576
CMP -- 9% 81
USGen -- 13% 169
FPL -- 10% 100
Others -- 16% 45
100% 1756
In the Aroostook County market, qualifying renewable capacity is
currently divided, in large part, among only four competitors, HQ, MPS,
FPL and AEI, resulting in a highly concentrated market.
These figures are symptomatic of a relatively high degree of
market power. In the renewables market, the need for remedial
action is greater, however, than these market share numbers might
48. As we note below, however, if, as expected, the Commission acts by
rule to create a market in tradeable renewable credits, Aroostook County
effectively becomes a part of the New England geographic market.
-36-
otherwise suggest. This is because compliance with the portfolio
requirement is a prerequisite to entry into the Maine retail
market for electrical power generally. In short, players with
high renewables market shares may have the ability to deny their
marketing competitors entry into the Maine retail market simply
by refusing to make sufficient renewable power available at
wholesale. Such exclusionary tactics could dramatically decrease
competition for energy sales to Maine consumers, driving prices
up.
Of course, it can be argued that until a portfolio
requirement is adopted regionwide, relatively low demand for
renewable energy as such may reduce the ability of any player to
capitalize on market power in this product market. However, it
appears likely that variants of Maine's portfolio requirement
will be adopted by other New England states in due course.{49}
Moreover, it seems certain that numerous market participants will
seek to attract retail customer interest in green power across
the region. Demand for renewable power could therefore increase
sharply, regardless of portfolio requirements.{50}
49. Massachusetts has recently enacted a renewables standard which defines
"renewable" somewhat differently, and is designed to promote the development of
new sources of renewable power by requiring that retail sellers increase their
sales from new renewable sources each year by set percentages (from half to one
percent per year).
50. At the same time, the level of concentration shown in the table above
does not reflect that fact that the shares of at least two players, CMP and NU,
will diminish as their contracts with nonutility generators expire over the next
several years. The extent of the mitigating effect of this factor remains to
be analysed.
-37-
C. Remedial Options
The most obvious solution to the problem of market power in
the renewables market, as elsewhere, is divestiture. Again,
however, Maine cannot legislatively require divestiture of
renewable generation sources by either NU or USGen. On the other
hand, the restructuring statute does require divestiture by CMP
and MPS. CMP will be presenting its proposed sale to FPL to the
Commission for approval in the near future; an MPS auction is
currently under way. As we have noted above, the Commission
clearly has the power, under the statute, to refuse to approve,
or place conditions upon a proposed acquisition on market power
grounds.{51}
There is a further remedial option available to the
Commission under the statute as written which would serve to
reduce concentration in both geographic markets, and especially
in Aroostook County, by effectively joining them together. The
Commission could act by rule to create a market in "tradeable
credits."{52} Generators with facilities which met the statutory
definition could apply to the Commission for credits (e.g. one
credit per renewable kilowatt hour generated annually). At
year-end, retailers would be required to turn over to the
Commission credits totalling 30% of their sales. The rule would
explicitly envisage the development of a market for the renewable
credits along the same lines as markets for sulphur dioxide emission
51. However, in view of the fact that CMP's proposed sale effectively
splits its renewable capacity in two, reducing the HHI for this market below the
1800-mark, it is not clear that the imposition of additional conditions on this
transaction could achieve any significant further reduction in concentration.
52. The Commission has expressed its interest in this remedial option as
a matter of record.
-38-
credits under Title IV of the federal Clean Air Act amendments.
The market in tradeable renewable credits could function as an
adjunct to energy markets, without regard to the geographic
separation of Aroostook County from the New England energy
markets.
Other, more general remedial options are also available, and
merit consideration in the context of the final report.
Specifically, it may be advisable, in view of the ability of
players with high renewable market shares to exclude competitors
from the Maine retail energy market altogether, to provide some
sort of legislative "safety valve" designed to prevent an adverse
impact on consumers. We have identified two such options.
First, provision could be made by rule or statute to the
effect that if a prospective entrant to the Maine market could
not obtain the required level of renewables for inclusion in its
energy mix, it could nevertheless enter on the strength of a
promise to make good the renewable "deficit", with "interest", at
a later time. This would give the entrant the opportunity to
acquire or construct its own renewable energy source. Second,
prospective entrants could be given the option, instead of
fulfilling the portfolio requirement, of making a contribution to
a fund to be used to promote renewables. These two measures
could, of course, be adopted in tandem.
D. Recommendations
No legislative correction or addition is recommended at this time. However,
market power considerations should reinforce the Commission's interest in the
-39-
creation of a market in tradeable renewable credits. The final report will
give consideration to amending the restructuring statute to build in a
safety valve designed to prevent players with high renewable
market shares from excluding competitors from the Maine retail
energy market, unless this has already been accomplished by rule.
VI. CONCLUSION
In this Interim Report, we offer a preliminary assessment of
the market power problems which appear likely to affect
restructured electric markets in Maine or of which Maine forms a
part. We conclude that there is no current need for emergency
legislation in this legislative session to address market power
issues. However, we plan to carefully review legislative options,
and to offer specific legislative recommendations in the final
report, due December 1, 1998.
Under the restructuring statute, Maine's retail electric
markets will be vulnerable, to some degree, to vertical market
power arising from the ability of t&d companies to participate in
the retail market through affiliated power marketers. In the
final report, we plan to reassess the efficacy of the regulatory
restrictions imposed by the restructuring statute as a solution
to the problem of vertical market power, and to offer a
recommendation as to whether the Legislature should reconsider an
outright ban on affiliate marketing.
The New England and Aroostook County wholesale electric
markets are highly concentrated, and accordingly, subject to
horizontal market power to a significant degree. Because
wholesale rates are within the exclusive jurisdiction of federal
-40-
authorities, however, legislative options are limited. The final
report will consider the advisability of legislative adjustments
to the restructuring statute in the area of demand side
management, transmission enhancements, and possible amendments to
unfair trade practices or profiteering in necessities laws. In
the meantime, the Department will continue to pursue other
remedial options, including advocacy before FERC and antitrust
merger enforcement. With respect to Aroostook County, or in the
event that a load pocket is found to exist in southern and
central Maine, the Commission possesses the ability to impose
conditions in the context of pending divestiture proceedings to
reduce levels of concentration. Finally, the final report will
consider whether, in the light of intervening developments, how best to
prepare the Aroostook County market for retail choice.
The New England wholesale market for renewable energy as
defined in the restructuring statute is moderately concentrated.
Its Aroostook County counterpart is highly concentrated. There is
special reason for concern, here, in that competitors with high
market shares may possess the ability to deny others entry to
Maine's energy markets generally. Even so, legislation may not be
necessary in this area. CMP's proposed sale to FPL (if approved) will
have reduced levels of concentration somewhat; the Commission
retains the ability to impose conditions on MPS' proposed
divestiture, if necessary.
More importantly, by acting to create by rule a market in tradeable
renewable credits, the Commission can effectively annex Aroostook County to the
less concentrated New England market. In addition, the Commission can act by
rule to
-41-
ensure access to Maine energy markets by permitting competitors to run a
renewable deficit, or to pay into a fund in lieu of strict compliance with the
portfolio requirement. The final report will review the need for legislation
in light of intervening developments.
-42-
Exhibit 99(q)
STATE OF MAINE
PUBLIC UTILITIES COMMISSION Docket No. 97-727
January 15, 1998
MAINE PUBLIC SERVICE COMPANY ORDER GRANTING
Application for Approval of an Electric CERTIFICATE OF
Rate Stabilization Agreement with APPROVAL
Wheelabrator-Sherman
WELCH, Chairman; NUGENT and HUNT, Commissioners
_________________________________________________________________
I. SUMMARY
In this Order, we issue a certificate of approval for an
electric rate stabilization agreement (Agreement) submitted by
Maine Public Service Company (MPS). (1) The Agreement restructures
an existing power purchase agreement (PPA) between MPS and
Wheelabrator-Sherman (W/S) consistent with statutory
requirements.
II. BACKGROUND
On September 19, 1997, MPS filed, pursuant to 35-A M.R.S.A.
S. 3156, for approval of an electric rate stabilization agreement
that amends its current W/S PPA. Under the existing PPA, MPS
must purchase up to 126,582 MWh per year from W/S's 17.6 MW
biomass plant in Sherman Station; the W/S plant is a qualifying
facility (QF) pursuant to 35-A M.R.S.A. S. 3303. The existing PPA
specifies power purchase rates for an initial 15-year term
(through the year 2000), and allows either party to extend the
PPA for an additional 15 years at negotiated or Commission-set
rates.
The proposed Agreement includes three elements. First, MPS
would pay W/S $8.6 million at closing; this amount would be
financed by the Finance Authority of Maine (FAME) pursuant to
10-M.R.S.A. S. 963(7-A). MPS would also pay W/S an additional
$2,350 per day (up to a maximum of $105,750) for each day closing
is delayed past November 1, 1997. Second, W/S would provide
monthly credits to MPS for the remainder of the PPA initial term.
These credits total $10 million (nominal) and have a present
value of approximately $8 to $9 million. The rates in the
initial term of the PPA (1986-2000) do not change. Third, the
Agreement would reduce the PPA extension period from 15 to 6
years, increase the purchase obligation in each of the extension
1. Commissioner Hunt voted against this decision. See
attached Dissenting Opinion.
Order Granting . . . -2- Docket No. 97-727
term years by 10,000 MWh to 136,582 MWh, and establish purchase
prices for power beginning at $.0854 per kWh in 2001 and
escalating at 2% per year.
In addition to its request for approval of the Agreement,
MPS filed a motion to modify its current rate plan (2) so that
savings in the near term from the Agreement can be used to offset
rate increases during the remaining term of the rate plan. Under
MPS's current rate plan, savings from any restructuring of the
W/S PPA would reduce specified deferrals that would be recovered
in rates beginning in 2000. MPS has also filed two other
motions, both designed to obtain Commission assurance that all
costs of the Agreement will be recovered in rates.
During a prehearing conference held on October 10, 1997, the
Hearing Examiner granted the petitions to intervene of the Public
Advocate and Houlton Water Company. W/S did not petition to
intervene, but participated throughout the proceeding by
presenting its views of the benefits of the Agreement. The
Commission held a hearing on this matter on November 4, 1997.
On November 14, 1997, the Commission issued an Order Denying
Certificate of Approval, without prejudice, stating that it was
unable to find, at that time, that the potential future costs of
the Agreement were not likely to be disproportionate to near-term
savings. The Commission encouraged MPS to re-file its petition
for approval to allow more time to develop an informed judgment
as to the long-term economics of the Agreement. (3) MPS filed a
letter resubmitting its petition on November 6, 1997. (4)
III. POSITIONS REGARDING THE AGREEMENT
A. Maine Public Service Company
In its initial filing, MPS requests approval of the
Agreement as satisfying the requirements of section 3156. MPS
states that the Agreement will produce near-term savings that
will be reflected in rates and estimates the overall net present
value (NPV) savings of the Agreement to be $362,000. This
2. MPS is currently operating under a multi-year rate plan
approved by the Commission on November 30, 1995 (Docket No. 95-052).
3. Under section 3156, the Commission must issue or deny a
certificate within 60 days of an application.
4. MPS filed this letter in reaction to the Commission
deliberations of this matter that occurred on November 4, 1997.
Order Granting . . . -3- Docket No. 97-727
estimated overall savings is based on MPS's view of the likely
range of outcomes if the renewal term rates were litigated before
the Commission. (5)
MPS argues that the Agreement provides certain
near-term benefits ($10 million reduction in PPA costs over 3
years) and that possible future rate impacts are not likely to be
disproportionate; some amount of future uncertainty should be
tolerated to obtain near-term savings. MPS notes that W/S has
advanced some positions that appear credible and supportable, and
that full litigation of the renewal term rates could result in an
outcome that would be very expensive relative to the Agreement.
Finally, MPS states that the outcome of renewal term rate
litigation cannot be conclusively determined and that there are
reasonable analyses showing a positive NPV; as such, the
Commission should approve the Agreement to obtain the near-term
savings and avoid a substantial litigation risk regarding future
contract rates.
B. Public Advocate
The Public Advocate also supports approval of the
Agreement, but does so cautiously. The Public Advocate states
that the Agreement's savings, if any, cannot be calculated, that
the Company's calculation relies on speculation as to the renewal
term rates, and that the economics could range from substantial
costs to substantial savings. The Public Advocate is concerned
that the Agreement could provide near-term benefits at the cost
of raising rates after 2000.
However, the Public Advocate supports the Agreement
because of the significant reduction in risk it represents to MPS
and its ratepayers by shortening the exposure to the W/S PPA;
even if there are no net savings, there is a large benefit in the
PPA terminating as soon as possible. In the Public Advocate's
view, because no one can predict the outcome of litigation, the
reduction of risk exposure of this magnitude subsumes other
costs, benefits and analyses presented by the PPA restructuring
proposal.
5. As we discuss below, the economics of the Agreement are
extremely sensitive to assumptions of what the renewal term rates
would be in the absence of the Agreement. MPS provided its
position on the appropriate outcome (as opposed to the likely
outcome) of litigation on the renewal term rate; if MPS prevailed
in its position, the Agreement would have a NPV cost of
approximately $10 million.
Order Granting . . . -4- Docket No. 97-727
C. Wheelabrator-Sherman
W/S disagrees that the Agreement could result in any
substantial losses to ratepayers in comparison to the unamended
PPA. On the contrary, W/S argues that the Agreement, based on
its view of the proper approach for establishing the renewal term
rates, will save ratepayers millions of dollars. For these
reasons, W/S urges the Commission to approve the Agreement.
IV. DISCUSSION OF AGREEMENT
Electric rate stabilization agreements are governed by
section 3156. The section allows the Commission to issue a
certificate of approval only if it makes five explicit findings.
Before discussing the individual required findings, we present
our general views regarding of the Agreement and why its approval
is in the public interest.
In the near-term, the Agreement will undoubtedly provide
savings in the range of $3.5 million NPV through 2000. However,
the overall economics of the Agreement depend on inherently
speculative assumptions of what the renewal term rates would be
in the absence of the Agreement. Renewal term rates would be
determined based on the following language contained in the
existing PPA:
the rates shall be based on avoided capacity
costs of the same plant on which avoided
capacity rates were based at the outset of
this contract and on avoided energy costs.
The parties agree to negotiate in good faith
to set the avoided energy and capacity costs
upon which rates shall be based. In the
event the Buyer and Seller are unable to
agree to the rate, the Buyer and Seller agree
to submit the dispute to the Maine Public
Utilities Commission.
The record contains three conceptual approaches to
calculating the renewal term rates that lead to widely divergent
results:
- Estimates of Seabrook I (6) fixed costs and MPS
system energy costs during 2001-2005;
- Estimates of Seabrook I fixed and variable costs
during 2001-2005;
6. Seabrook I is the plant on which the Commission initially
based avoided capacity rates.
Order Granting . . . -5- Docket No. 97-727
- Estimates of the market value of Seabrook I during
2001 through 2015.
Depending on the approach used, the net present value of the
Agreement could range from approximately $35 million in savings
if Seabrook fixed costs and system energy are used, to
approximately a $21 million NPV cost if market value were to be
employed. Estimates using Seabrook fixed and variable costs
range from approximately a $10 million cost to a $5 million
savings.
Assessing the value of the Agreement is further
complicated by the non-specific nature of the renewal term
language and the purpose for which the provision was initially
included in the PPA. The provision was included at the urging of
MPS so it would not lose the benefit of what it believed to be
relatively low cost Seabrook power in the out-years compared to
what it believed to be relatively higher cost alternatives.
However, the situation turned out to be the opposite whereby
Seabrook power is relatively more costly than currently existing
alternatives. These circumstances present the Commission with an
extremely difficult task of attempting to project the renewal
term rates it would establish if the matter was disputed and
brought to it for resolution, as well as considering the outcome
of a court challenge.
We must consider the analytical task presented by this
case in light of the statutory language contained in section
3156. Section 3156 appears to contain a bias in favor of
near-term savings even at the expense of some increased level of
long-term cost. Under the statute, we must find an agreement
"will provide near-term benefits." We must then find that
"[p]otential future adverse rate impacts . . . are not likely to
be disproportionate to near-term gains." We read this language
to mean that, if there are reasonably certain near-term savings,
a rate stabilization agreement can be approved even if it results
in overall increased costs, as long as those increased costs are
not "disproportionate" to the near-term gains.
In this case, there are clear near-term benefits.
Although there are reasonable scenarios upon which future adverse
rate impacts would overwhelm those near-term benefits, there are
also plausible (albeit not likely) (7) futures by which a rejection
7. Although W/S argues strenuously that use of Seabrook I
fixed costs and system energy was the intent of the renewal term
provision, such an approach is a conceptually incorrect method of
calculating avoided costs that would result in a windfall to W/S
at the expense of MPS ratepayers.
Order Granting . . . -6- Docket No. 97-727
of the Agreement would not only result in the loss of the
near-term gains, but cause ratepayers substantial adverse rate
impacts throughout the next 15 years. Many of the likely
scenarios, however, fall within an overall NPV range of
approximately a $5 million cost to a $5 million benefit. On
balance, we believe it is important to eliminate the risk of a
substantial adverse outcome to ratepayers from litigation of the
renewal term rates; it is also preferable to risk making a 6-year
mistake rather than a 15-year mistake. By approving the
Agreement, we ensure the near-term benefits for ratepayers as
well as providing certainty that a power contract that has
created a severe financial burden on MPS and its ratepayers over
many years will conclude in 2006. It is on the basis of these
considerations, that we view the Agreement to be in the public
interest.
We now address specifically the five statutory findings
required by section 3156.
1. The Agreement and any assistance in FAME financing
will provide near-term benefits to ratepayers that
will be reflected in rates.
As mentioned above, the Agreement will result in
near-term benefits in the range of $3.5 million NPV through 2000.
As discussed below, we will modify the terms of MPS's current
rate plan to allow a near-term flowthrough of the Agreement's
benefits over the remaining years of the plan. Because we will
proceed in this matter, the near-term benefits will be reflected
in rates.
2. Potential future adverse rate impacts are not
likely to be disproportionate to near-term gains.
This required finding relates to the overall net
benefits or costs that the Agreement is likely to produce over
its term. As discussed above, this issue depends on the
inherently speculative question of what the renewal term rates
would be in the absence of the Agreement. Based on the record in
this case, and taking into account the great amount of
uncertainty of any long-term analysis of this Agreement, we find
that the potential for future adverse rate impacts is not likely
to be disproportionate to the near-term gains.
Order Granting . . . -7- Docket No. 97-727
3. The Agreement does not have as a necessary or
probably consequence the permanent cessation of a
QF of more than 50 MW.
Because the W/S facility is less than 50 MW, we
make this third finding.
4. The Agreement is consistent with the Maine Energy
Policy Act.
The Maine Energy Policy Act, 35-A M.R.S.A. s. 3191,
requires utilities to pursue a least cost energy plan, taking
into account many factors including costs, risk and diversity of
supply. For many of the reasons discussed above, we find that
the Agreement is consistent with section 3191. Although we
cannot say with certainty whether the long-term impacts of the
Agreement will be positive or negative, the Agreement does reduce
near-term costs as well as long-term risks without, as discussed
below, adversely effecting the diversity supply. In this way,
the Agreement is consistent with sound least cost planning.
5. The Agreement will not adversely impact the
availability of a diverse and reliable mix of
energy resources and will not significantly reduce
the availability of long-term resources to meet
electric demand.
The approval of the Agreement ensures that the W/S
facility will be part of the energy mix until the year 2006. In
the absence of the Agreement, it is possible that the facility
would cease to operate after 2000 or continue to operate pursuant
to the MPS PPA until 2015. It is also be possible that the
facility would continue to operate in the competitive generation
market after 2006 when the Agreement expires. Even if the plant
ceases to operate after 2006, Maine continues to have a
relatively diverse energy mix. For these reasons, we find that
the Agreement will not have an adverse impact on the diversity
and reliability of the energy mix or significantly reduce the
available of long-term resources.
V. MPS MOTIONS
As mentioned above, MPS filed a series of motions, seeking
specified Commission findings. The motions are: (1) Motion to
Alter or Amend the Commission's November 30, 1995 Order in Docket
No. 95-052 (Order that approved MPS's rate plan); (2) Motion to
Amend the Commission's February 10, 1984 and June 4, 1984 Orders
in Docket Nos. 81-276, 83-264, and 83-303; and (3) Motion for
Investigation into Recovery of Stranded Costs created by the
Order Granting . . . -8- Docket No. 97-727
Agreement (this third motion seeks to serve the same purpose as
the second motion).
In the first motion, MPS asks the Commission to modify the
provisions of its rate plan to allow the Agreement's near-term
savings to offset the increases it would otherwise seek in
upcoming annual reviews. Under the terms of MPS's rate plan, any
reductions to the cost of the W/S PPA must be used to reduce
specified deferrals that would otherwise be included in rates
beginning in 2000. MPS states that the requested modification
will reduce necessary immediate rate increases and allow for
near-term benefits to flow to ratepayers, which is a prerequisite
of section 3156. The purpose of the second and third motions is
to obtain the Commission determination that the Agreement is
consistent with the original orders approving the W/S PPA and to
ensure that any stranded costs created by the Agreement (as
opposed to the original PPA) will be recovered in rates.
During the hearing on this matter, MPS clarified that it
would be satisfactory for the Commission to make a general
finding that it would modify the rate plan to allow for the
near-term flowthrough of benefits during the term of the rate
plan, without any specific indication of the manner by which this
would be accomplished. MPS also indicated that it would be
sufficient for the Commission to interpret the provisions of
section 3156 and section 3208 (the stranded cost section of the
restructuring legislation) to mean that the Company will recover
in rates the Agreement's financing costs and costs of the PPA
extension.
We find that it is reasonable to amend the MPS rate plan to
allow a near-term flowthrough of the benefits of the Agreement
during the Company's rate plan. No party has opposed this change
in concept and it is certainty consistent with the Legislature's
intent that the ratepayers realize the near-term benefits from
FAME financed QF contract renegotiations in their rates. The
specific timing of the flowthrough of the benefits will be
considered as part of MPS's pending rate plan annual review,
Docket No. 97-830.
We also find that under the provisions of sections 3156 and
3208, MPS should recover from its ratepayers the financing costs
and costs of the PPA extension associated with the Agreement.
Section 3156 states that the Commission may not disallow or
prevent the recovery of electric utility costs, including costs
to be paid to the QF, under the terms of a rate stabilization
agreement based solely on the execution of the certified
agreement. Section 3208 provides that utilities may recover
legitimate, verifiable and unmitigatable stranded costs. These
provisions evidence a legislative intent that MPS recover the
Order Granting . . . -9- Docket No. 97-727
costs associated with the Agreement. These include the costs
involved with the $8.6 million payment to W/S and the payments
for the extension term power purchases (2001-2006). (8)
Accordingly, we
O R D E R
A certificate of approval for the electric rate
stabilization agreement filed by Maine Public Service Company on
September 18, 1997, is hereby issued.
Dated at Augusta, Maine this 15th day of January, 1998.
BY ORDER OF THE COMMISSION
______________________________
Dennis L. Keschl
Administrative Director
COMMISSIONERS VOTING FOR: Welch
Nugent
COMMISSIONER VOTING AGAINST: Hunt: See attached Dissenting
Opinion
8. Consistent with the treatment of stranded costs, MPS would
recover only the cost of the power purchases net of the power's market
value.
Order Granting . . . -10- Docket No. 97-727
Dissenting Opinion of Commissioner Hunt
I would not approve Maine Public Service's proposed
amendment to its Purchased Power Agreement with Wheelabrator
Sherman. I do not believe the record supports one prong of
Section 3156, which requires us to find that the potential for
future adverse rate impacts are not likely to be disproportionate
to the near-term gains.
Staff's analysis suggests that the 1997 amendment could
result in a substantial loss to ratepayers in comparison to the
unamended PPA over the longer term. Pursuant to that analysis,
the Agreement is more likely than not to result in a significant
NPV cost in an amount disproportionate to the near term savings.
I do not express an opinion about what the conclusion would be if
the matter were litigated before the Commission. As the OPA
observed, one cannot "calculate with any degree of accuracy how
much, if anything, the Company and its ratepayers will save by
virtue of this agreement." I believe, however, that the
Commission has reasonable and sound options regarding the methods
to establishing renewal term rates that would withstand judicial
scrutiny and that, if adopted, would result in lower long term
costs for MPS ratepayers.
I agree with the majority that removing the risks inherent
in litigation has some value. However, as the contract
provision which governs the renewal term rates provides that a
dispute over rates would be submitted to the Commission, and as
the renewal provision is vague, a reviewing court would likely
give the Commission discretion, provided our decision had record
support and was theoretically sound. Over the long term, it is
likely that ratepayers may be better positioned if the Commission
rejected the Amendment as proposed.
Order Granting . . . -11- Docket No. 97-727
NOTICE OF RIGHTS TO REVIEW OR APPEAL
5 M.R.S.A. S. 9061 requires the Public Utilities Commission
to give each party to an adjudicatory proceeding written notice
of the party's rights to review or appeal of its decision made at
the conclusion of the adjudicatory proceeding. The methods of
adjudicatory proceedings are as follows:
1. Reconsideration of the Commission's Order may be
requested under Section 6(N) of the Commission's Rules of
Practice and Procedure (65-407 C.M.R.11) within 20 days of
the date of the Order by filing a petition with the
Commission stating the grounds upon which consideration is
sought.
2. Appeal of a final decision of the Commission may be
taken to the Law Court by filing, within 30 days of the date
of the Order, a Notice of Appeal with the Administrative
Director of the Commission, pursuant to 35-A M.R.S.A. S. 1320
(1)-(4) and the Maine Rules of Civil Procedure, Rule 73 et
seq.
3. Additional court review of constitutional issues or
issues involving the justness or reasonableness of rates may
be had by the filing of an appeal with the Law Court,
pursuant to 35-A M.R.S.A. S. 1320 (5).
Note: The attachment of this Notice to a document does not
indicate the Commission's view that the particular document
may be subject to review or appeal. Similarly, the failure
of the Commission to attach a copy of this Notice to a
document does not indicate the Commission's view that the
document is not subject to review or appeal.
[ARTICLE] UT
[MULTIPLIER] 1,000
[PERIOD-TYPE] 12-MOS
[FISCAL-YEAR-END] DEC-31-1997
[PERIOD-END] DEC-31-1997
[BOOK-VALUE] PER-BOOK
[TOTAL-NET-UTILITY-PLANT] 49865
[OTHER-PROPERTY-AND-INVEST] 4129
[TOTAL-CURRENT-ASSETS] 15526
[TOTAL-DEFERRED-CHARGES] 94032
[OTHER-ASSETS] 0
[TOTAL-ASSETS] 163552
[COMMON] 7357
[CAPITAL-SURPLUS-PAID-IN] 38
[RETAINED-EARNINGS] 26903
[TOTAL-COMMON-STOCKHOLDERS-EQ] 34298
[PREFERRED-MANDATORY] 0
[PREFERRED] 0
[LONG-TERM-DEBT-NET] 35650
[SHORT-TERM-NOTES] 7200
[LONG-TERM-NOTES-PAYABLE] 0
[COMMERCIAL-PAPER-OBLIGATIONS] 0
[LONG-TERM-DEBT-CURRENT-PORT] 4155
[PREFERRED-STOCK-CURRENT] 0
[CAPITAL-LEASE-OBLIGATIONS] 0
[LEASES-CURRENT] 0
[OTHER-ITEMS-CAPITAL-AND-LIAB] 82249
[TOT-CAPITALIZATION-AND-LIAB] 163552
[GROSS-OPERATING-REVENUE] 55072
[INCOME-TAX-EXPENSE] (975)
[OTHER-OPERATING-EXPENSES] 55136
[TOTAL-OPERATING-EXPENSES] 54161
[OPERATING-INCOME-LOSS] 911
[OTHER-INCOME-NET] 495
[INCOME-BEFORE-INTEREST-EXPEN] 1406
[TOTAL-INTEREST-EXPENSE] 3583
[NET-INCOME] (2177)
[PREFERRED-STOCK-DIVIDENDS] 0
[EARNINGS-AVAILABLE-FOR-COMM] (2177)
[COMMON-STOCK-DIVIDENDS] 1617
[TOTAL-INTEREST-ON-BONDS] 3092
[CASH-FLOW-OPERATIONS] (1719)
[EPS-PRIMARY] (1.346)
(1.346)