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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, 1996. 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. [X]
Aggregate market value of the voting stock held by non-affiliates at
March 19, 1997: $23,450,125
The number of shares outstanding of each of the issuer's classes of
common stock as of March 19, 1997.
Common Stock, $7.00 par value - 1,617,250 shares
DOCUMENTS INCORPORATED BY REFERENCE
1. The Company's 1996 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, 1996, which
is the end of the fiscal year covered by this report, is incorporated by
reference into Part III.
(Page 1 of 45 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 1996, sales to the Company amounted to
137,615 MWH out of the 163,043 MWH generated for sale at Tinker.
The Company and the Subsidiary's net energy production, including
generated and purchased power, required to serve all customers, was
800,775 MWH for the twelve months ended December 31, 1996. The
following table sets forth the sources from which the Company and the
Subsidiary obtained their power requirements in 1996.
1996 Megawatt-hours Generated
Sources of Power or Purchased
Net Generation:
Hydro 168,993
Steam 10,201
Diesel (674)
Total 178,520
Purchases:
Nuclear Generated 249,083
Fossil Fuel Generated 243,720
Biomass Generated 128,711
Total 621,514
Inadvertent Received 741
Total System 800,775
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PART I Form 10-K
Item 1. Business - Continued
As of June 4, 1984, the Company entered into a Power Purchase
Agreement with Sherman Power Company, which assigned its interest in the
Agreement to Wheelabrator-Sherman Energy Company, formerly Signal-
Sherman Energy Company, (a cogenerator), for approximately 18 MW of
capacity which began July, 1986. The contract expires in 2001.
Financial Information about Foreign and Domestic Operations
Financial Information Relating
To Foreign and Domestic Operations
(In Thousands of U.S. Dollars)
1996 1995 1994
Revenues from
Unaffiliated Customers:
Company-United States 56,521 54,585 57,662
Subsidiary-Canada 743 694 706
Intercompany Revenues:
Company-United States 683 719 646
Subsidiary-Canada 2,424 1,877 1,824
Operating Income:
Company-United States 4,585 3,997 7,932
Subsidiary-Canada 703 367 387
Income before Extraordinary Items
Company-United States 1,366 503 4,469
Subsidiary-Canada 745 418 377
Extraordinary Items, Net of Tax
Company-United States - (6,236) -
Net Income (Loss)
Company-United States 1,366 (5,733) 4,469
Subsidiary-Canada 745 418 377
Identifiable Assets:
Company-United States 109,891 107,138 115,912
Subsidiary-Canada 6,823 6,936 6,463
The identifiable assets, by company, are those assets used in each
company's operations, excluding intercompany receivables and
investments.
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PART I Form 10-K
Item 1. Business - Continued
Source of Revenues
In 1996, consolidated operating revenues totaled $57,264,165.
The percentages of revenues derived from customer classes are as
follows:
%
Residential 34.9
Small Commercial and Industrial 28.7
Large Commercial and Industrial 17.6
Public Authorities 1.2
Sales to Wholesale Customers for Resale 3.7
Other Sales and Other Revenues 13.9
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
a 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 3.5% of consolidated MWH sales and 2.4% of consolidated
operating revenues for the year ended December 31, 1996.
The closing of Loring Air Force Base (Loring) was completed in
September, 1994, and accounts for the small percentage of total revenues
from Public Authorities. In 1993, when the Base was operating for the
entire year, Loring accounted for 7.3% of consolidated MWH sales and
5.7% of consolidated operating revenues. A civilian authority is now
the caretaker of the facility charged with finding tenants. The
Department of Defense has established a Defense Finance and Accounting
Service Center, which will employ approximately 600 people when fully
implemented. In addition, Loring was chosen as a Jobs Corp Center,
which opened in early 1997. In February 1997, a hardwood floor
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PART 1 Form 10-K
Item 1. Business - Continued
manufacturer announced they would locate at Loring, which will create
approximately 30 new jobs.
The Company has offered load retention rates to several major
industrial customers. These customers have the option to self-generate;
however, the Company believes it can compete with self-generation.
During 1996, the Company entered long-term power contracts with two of
its largest customers. The prices under these contracts are lower than
permitted under the Company's standard rates, but obligates them to
purchase all of their electrical requirements through the year 2000.
One additional customer has signed a similar agreement that must be
approved by the MPUC, while two others have verbally accepted the
Company's offers. Any load retention rates must be approved by the
Maine Public Utilities Commission.
On November 13, 1995, the Maine Public Utilities Commission
approved a Stipulation signed by Maine Public Service Company, the
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(b) of the "Legal Proceedings" section of this Form 10-
K.
For additional discussion on revenues, see the 1996 Annual Report
to Stockholders, pages 3 and 4, "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
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PART I Form 10-K
Item 1. Business - Continued
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.
See the 1996 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 possible 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 1996
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
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PART I Form 10-K
Item 1. Business - Continued
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 Parent Company owns 5% of the Common Stock of the Maine Yankee
Atomic Power Company (Maine Yankee). Maine Yankee owns and operates an
860,000 kilowatt nuclear generating plant in Wiscasset, Maine. The
Company is entitled to purchase approximately 4.9% of the energy
produced by the plant. During 1996, 1995 and 1994, purchases from Maine
Yankee were $10,185,000, $7,972,000 and $9,645,000, respectively.
In 1996, Maine Yankee provided approximately 31.1% of the Company's
energy requirements. In early February of 1995, during a scheduled
refueling-and-maintenance shutdown, Maine Yankee detected an increased
rate of degradation of the Plant's 17,000 steam generator tubes in
excess of the number expected and started evaluating several courses of
action. Maine Yankee could not resume operations until the necessary
repairs had been made.
Maine Yankee repaired the tubes by inserting and welding short
reinforcing sleeves of an improved material in almost all of the steam
generator tubes. The sleeving of the steam generator tubes was not
completed until mid-December of 1995, at a cost of approximately $27
million, with the Company's share being approximately $1.3 million.
During 1995, while Maine Yankee was out of service, the Company incurred
additional replacement power costs of approximately $5.7 million. As
more fully explained in the "Regulatory Proceeding - Four-Year Rate Plan
Approved" section of the Company's 1996 Annual Report, incorporated
herein by reference, and Item 3(b) of the "Legal Proceedings" section of
this Form 10-K, in late 1995 the Maine Public Utilities Commission
(MPUC) approved a multi-year rate plan for the Company. As an element
of the rate plan, the Company eliminated the fuel adjustment clause
except for the cost of power purchased from the Wheelabrator-Sherman
Energy Company, an independent power producer. As part of the rate
plan, $2.1 million, net of income taxes, of the replacement power costs
associated with the Maine Yankee outage was written off in 1995,
$300,000, net of income taxes, will be collected in rates and amortized
over the four-year rate plan period, and an estimated $1.3 million, net
of income taxes, will be deferred until 2000, when rate recovery will be
provided. The rate plan also includes a mechanism to handle similar
unexpected Maine Yankee outages during the rate plan period. In
addition, the rate plan allows for the five-year amortization of the
actual sleeving expenses.
On December 4, 1995, when the sleeving project was substantially
complete, Maine Yankee obtained a copy of a letter from an organization
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PART I Form 10-K
Item 1. Business - Continued
with a history of opposing nuclear power development to a State of Maine
nuclear safety official based on documentation from an anonymous
employee or former employee of Yankee Atomic Electric Company (Yankee),
an affiliate of Maine Yankee that has regularly performed nuclear
engineering and related services for Maine Yankee and other nuclear
plant operators. The letter contained allegations that Yankee knowingly
performed inadequate analyses to support two license amendments to
increase the rated thermal power at which the Maine Yankee Plant could
operate. It was further alleged in the letter that Maine Yankee
deliberately misrepresented the analyses to the Nuclear Regulatory
Commission (NRC) in seeking the license amendments. The allegedly
inadequate analyses related to the operation of the Plant's emergency
core cooling system (ECCS) and the calculation of the Plant
containment's peak postulated accident pressure, both under certain
assumed accident conditions. The analyses were used in support of
license amendments that authorized Plant power uprates from 2,440
megawatts thermal, a level equal to approximately 90 percent of the
maximum electrical capability of the Plant, to its current 100-percent
rated level.
The NRC's office of the Inspector General ("OIG") and its Office of
Investigation ("OI") initiated separate investigations of the
allegations made in the letter. On May 9, 1996, the OIG, which was
responsible for investigating only the actions of the NRC staff and not
those of Maine Yankee and Yankee Atomic, reported on its investigation,
finding deficiencies in the NRC staff's review, documentation, and
communications practices in connection with the license amendments, as
well as "significant indications of possible licensee violations of NRC
requirements and regulations." Any such violations by Maine Yankee
would be within the purview of the OI investigation, which, with related
issues, is being reviewed by the United States Department of Justice.
A separate internal investigation authorized by the boards of directors
of Maine Yankee and Yankee Atomic and conducted by an independent law
firm noted several areas for improvement, including regulatory
communications, definition of responsibilities between Maine Yankee and
Yankee Atomic, and tracking and documentation of regulatory compliance,
but found no wrongdoing by Maine Yankee or Yankee Atomic or any of their
employees. The Company cannot predict the results of the investigations
by the OI and Department of Justice.
On January 3, 1996, the NRC issued a "Confirmatory Order Suspending
Authority For And Limiting Power Operation And Containment Pressure
(Effective Immediately) and Demand For Information" (the Order), after
reviewing the safety analyses performed by Yankee relating to Maine
Yankee's license amendment applications for the power uprates. The
Order limited the power output of Maine Yankee to approximately 90% of
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PART I Form 10-K
Item 1. Business - Continued
its rated maximum until the NRC reviewed and approved Plant-specific
analyses meeting the NRC's criteria for operation of the ECCS under
certain postulated accident conditions, in lieu of the analyses based on
the questioned computer code. The Order also required an integrated
containment analysis demonstrating that the maximum calculated
containment pressure under certain postulated accident conditions does
not exceed the design pressure of the Plant's containment. On January
10, 1996, Maine Yankee filed with the NRC information specified in the
Order that it believes supports operation of the Plant at up to 90% of
the Plant's capability. Maine Yankee attained the 90% level of the
Plant's capability on January 24, 1996.
On June 7, 1996, the NRC formally notified Maine Yankee that it
planned to conduct an "Independent Safety Assessment" (ISA) of the Maine
Yankee plant in conjunction with the State of Maine to provide an
independent evaluation of the safety performance of Maine Yankee and as
a "follow-up" to the NRC's OIG report. The NRC stated that the overall
goals and objectives of the ISA were: "(a) provide an independent
assessment of conformance to the design and licensing basis; (b) provide
an independent assessment of operational safety performance; (c)
evaluate the effectiveness of license self-assessments, corrective
actions and improvement plans and; (d) determine root cause(s) of safety
significant findings and conclusions." The NRC further informed Maine
Yankee that the ISA would be carried out by a team of NRC personnel and
contractors who were "independent of any recent or significant
involvement with the licensing, regulation, or inspection of Maine
Yankee."
On July 20, 1996, Maine Yankee went off-line to add pressure relief
valves to the primary component cooling system, as determined during a
comprehensive internal review by Maine Yankee of plant systems and
equipment. On September 2, 1996, the plant returned to service,
attaining the 90% capacity limit.
On October 7, 1996, the NRC released the results of the ISA at
Maine Yankee that concluded that although Maine Yankee was in general
conformance with its licensing basis, several items of deficient or weak
performance existed. The ISA report further concluded that the overall
performance at Maine Yankee was "adequate" for operation of the Plant.
The ISA report further concluded that the two principal causes for
these deficiencies were (1) that economic pressures to be a low-cost
power producer had limited resources to address corrective actions and
some improvements; and (2) that a questioning culture was lacking, which
had resulted in a failure to identify or properly correct significant
problems in areas perceived by Maine Yankee to be of low safety
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PART I Form 10-K
Item 1. Business - Continued
significance. In a letter to Maine Yankee accompanying the ISA report,
Chairman of the NRC Shirley Ann Jackson noted that although overall
performance at Maine Yankee was considered adequate for operation, a
number of significant weaknesses and deficiencies identified in the
report would result in NRC violations. The letter also directed Maine
Yankee to provide to the NRC its plans for addressing the root causes of
the deficiencies noted in the ISA and identified the NRC offices that
would be responsible for overseeing corrective actions and taking any
appropriate enforcement actions against Maine Yankee, including as-yet-
determined monetary penalties.
The plant went off-line again on December 6, 1996 to review and
resolve several cable separation and cable routing issues. Maine Yankee
will complete a root cause analysis of the cable issues and will present
the analysis to the NRC regional office prior to startup. Having
detected indications of minor leakage in a small number of the plant's
fuel rods, Maine Yankee has used this out-of-service time to inspect the
plant's 217 fuel assemblies and has determined that 68 of the fuel
assemblies should be replaced. In addition, 24 fuel assemblies will be
replaced as part of a refueling.
On December 10, 1996, Maine Yankee filed its formal response to the
ISA report. In this report, Maine Yankee promised to substantially
increase expenditures to address the source of the deficiencies noted in
the ISA report, and that the improvements would include physical and
operating changes to the Plant, as well as increased staffing, primarily
in the engineering and maintenance areas, and other changes.
Consequently, Maine Yankee's 1997 Operating Budget has been increased
by approximately $46.3 million for additional employees, training and
equipment in order to address the root causes of the deficiencies
identified in the ISA. The Company's share of this additional amount is
approximately $2.3 million.
Maine Yankee announced the resignation of President Charles D.
Frizzle on December 20, 1996. The Board of Directors of Maine Yankee
unanimously decided that new leadership was required to deal with deep-
rooted cultural issues, a changing regulatory environment, and
unprecedented financial pressures. On February 13, 1997, Maine Yankee
and Entergy Nuclear, Inc. ("Entergy"), which is a subsidiary of Entergy
Corporation, a Louisiana-based utility holding company and leading
nuclear plant operator, entered into a contract under which Entergy will
provide management services to Maine Yankee. At the same time, Michael
Sellman of Entergy assumed the office of President of Maine Yankee, and
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PART I Form 10-K
Item 1. Business - Continued
the contract contemplates that Entergy will provide other management
personnel to Maine Yankee.
On January 29, 1997, the NRC announced that it had placed the plant
on its "watch list", in "Category 2", which includes plants that display
"weaknesses that warrant increased NRC attention," but do not warrant a
shut-down order. The plant is one of 14 nuclear units in the United
States on the January 29 "watch list" and one of six listed there for
the first time.
The Company expects the plant to remain off-line until the fuel
assembly replacement and thorough inspections of the plant's electrical
cabling and steam generators are completed, and restarting is approved
by the NRC. The Company cannot predict how long the plant will remain
off-line, and will make replacement power plans for an outage that could
last through the summer of 1997.
The Company has been incurring replacement power costs of
approximately $170,000 per week while the plant has been out of service.
In addition, the Company is responsible for the previously mentioned
additional operating costs of $2.3 million associated with the ISA
inspection. Further costs are expected when Entergy Corporation begins
providing management services to Maine Yankee. Additional costs may
also be expected if the complexity of the cable-separation and
associated issues require an extended period for their resolution.
These additional costs can be expected to adversely impact the Company's
1997 financial results.
Under the Company's multi-year rate plan, as described in the
"Regulatory Proceedings - Four-Year Rate Plan Approved" section of the
Company's 1996 Annual Report, incorporated herein by reference, and Item
3(b) of the "Legal Proceedings" section of this form 10-K, the Company
has the right to receive specified retail rate increases through 1999.
This plan also includes provisions for additional cost recovery in
certain extraordinary situations such as very low earnings or in the
event of a Maine Yankee plant outage exceeding six consecutive months.
The Company will continue to assess whatever options it may have to
recover any additional costs and, in addition, is making every effort to
reduce its 1997 cash expenditures. These efforts will include a review
of the level of dividends on the Company's Common Stock.
Moreover, the Company's short-term revolving credit agreement, as
well as a letter of credit supporting its 1996 Series of tax-exempt
bonds, contain interest coverage tests that the Company must satisfy to
avoid default. The Company now believes, based on the projected
additional Maine Yankee expenses and replacement power costs during the
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PART I Form 10-K
Item 1. Business - Continued
plant outage, that it will likely be in violation of these interest
coverage tests for the twelve months ended March 31, 1997. The Company
will seek a waiver of these requirements from the necessary parties. The
Company anticipates that the waiver will be granted, but cannot predict the
terms of any such waiver.
In a related matter, a Maine-based group that originally announced
its intention to start gathering signatures toward a new referendum to
force a permanent closure of the plant by 2000, has now indicated its
intent to modify the referendum to prevent any renewal or extension of
Maine Yankee's operating license, currently due to expire in June 2008.
The group stated that it hoped to put the issues before the Maine
electorate in November, 1998. The Company cannot predict whether such
a referendum will be held or its outcome.
As an owner of Maine Yankee, the Company is responsible for its
proportional share of Maine Yankee operating expenses, including fuel
and decommissioning expenses. Furthermore, under a Capital Funds
Agreement, the Company, along with the other sponsoring utilities, has
agreed to provide Maine Yankee's capital requirements which cannot be
obtained from other sources. This obligation is limited to each owner's
interest in Maine Yankee, subject to obtaining necessary regulatory
approvals.
In 1994, pursuant to FERC authorization, Maine Yankee increased its
annual collection for decommissioning to $14.9 million, approximately
$735,000 a year for the Company. This increase was based on a new
decommissioning estimate, assuming dismantlement and removal, of $317
million (in 1993 dollars), as a result of an external engineering study.
As of December 31, 1996, Maine Yankee's decommissioning funds are valued
at $163.5 million. The decommissioning of nuclear power plants is
subject to changes in legal and regulatory requirements as well as
technological changes.
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 Maine Yankee and 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.
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PART I Form 10-K
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 56 6/1/94
Executive Officer
Frederick C. Bustard Vice President, 59 6/1/90
Power Supply & Environment
Larry E. LaPlante Vice President, 45 6/1/94
Finance, Administration and Treasurer
Stephen A. Johnson Vice President, 49 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.
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PART I Form 10-K
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 13, 1997.
There are no family relationships among the executive officers.
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.
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 expects that they will 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.
-14-
Form 10-K
PART I
Item 2. Properties - Continued
Placing Steam Units 1 and 2 on inactive status will save the
Company approximately $3.5 million over the five-year period. These
savings result primarily from a savings in operation and maintenance
expense. The Company eliminated 12 positions at the Plant and offered
a Company-wide voluntary early retirement program that was successful in
avoiding involuntary termination of some of the employees whose
positions at the units had been eliminated.
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, 1996, the Company and Subsidiary had
approximately 443 pole miles of transmission lines and the Company owned
approximately 1,603 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.
-15-
Form 10-K
PART I
Item 3. Legal Proceedings
(a) Maine Public Utilities Commission, Re: Electric Utility
Industry Restructuring Study, Docket No. 95-462.
In 1995, the Maine Legislature passed Resolve 89 "To
Require a Study of Retail Competition in the Electric
Utility Industry" (the "Resolve"), to begin a process for
developing recommendations on the future structure of the
electric utility industry in Maine. The process included
the appointment of a Work Group on Electric Utility
Restructuring to develop a plan for the orderly
transition to a competitive market for retail purchases
and sales of electricity. The Company participated in
this Work Group, which was unable to reach a consensus on
a recommended plan by its reporting deadline.
The Resolve also directed the MPUC to conduct a study to
develop at least two plans for the orderly transition to
retail competition in the electric utility industry in
Maine and to submit a report of its findings by January
1, 1997. One plan would be designed to achieve "... full
retail market competition for purchases and sales of
electric energy by the year 2000" and the other to
achieve a more limited form of competition. The Resolve
also stated that the MPUC's findings would have no legal
effect, but would "... provide the Legislature with
information in order to allow the Legislature to make
informal decisions when it evaluates these plans."
On December 12, 1995, the MPUC issued a Notice of Inquiry
(the "Notice") initiating its study. In the Notice, the
MPUC solicited detailed proposals and plans for achieving
retail competition in Maine by the year 2000 and
requested the proposals include specific plans for an
orderly transition to a more competitive market. The
Notice required that plans and proposals be filed with
the MPUC by interested parties no later than January 31,
1996, and outlined a schedule calling for submittal of a
final report to the Legislature in December, 1996.
On January 30, 1996, the Company filed its restructuring
proposal with the MPUC. The major elements of this
proposal were:
(a) The separation of the Company's generation assets
(including contracts and entitlements) from its
transmission and distribution assets. The Company
suggested this separation could be accomplished by either
-16-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
a functional separation of generation from distribution
and transmission within the Company's existing corporate
structure or by separating generation, on the one hand,
and distribution and transmission, on the other, into two
wholly-owned subsidiaries. The Company strongly opposes
any recommendation that it be required to divest itself
of its generation assets.
(b) The economic and resource planning regulation of
generation would cease. The FERC would continue to
regulate transmission, and distribution would remain a
franchised monopoly subject to continued regulation by
the MPUC. The owner of the distribution system would be
obligated to connect all willing customers.
(c) If certain necessary changes in the operation and
management of the regional transmission grid are in
place, all retail customers in Maine would, by the year
2000, be entitled to purchase electric energy directly
from any entity that wished to supply it to them.
(d) The Company would be entitled to full recovery of
all its stranded costs. This recovery would be
accomplished by a charge on the distribution system that
would apply to all retail customers. In its filing, the
Company estimates that its stranded costs could be as
high as $68 million. This amount consists primarily of
the above-market costs of the Company's contract with
Wheelabrator-Sherman, a non-utility generator, estimated
at $44 million and deferred regulatory assets, such as
its Seabrook investment of $24 million.
On December 31, 1996, the MPUC issued its Recommended
Plan on how to restructure Maine's electric utility
industry. The Plan recommends the following:
* As of January, 2000, all Maine consumers would
have the option to choose an electric power
supplier.
* As of January, 2000, Maine would not regulate,
as public utilities, companies producing or selling
electric power.
* Regulated public utilities would continue to
provide electric transmission and distribution
(T&D) services.
-17-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
* As of January, 2000, the Company, Central
Maine Power Company (CMP) and Bangor Hydro-Electric
Company (BHE), the State's three largest electric
utilities, would be required to structurally
separate their generation assets and functions from
transmission and distribution functions. CMP and
BHE would be required to fully divest themselves of
their generation assets by 2006.
* The Plan does not recommend generation
divestiture for the Company, but instead proposed
to allow the Company to retain its generation
assets in a separate, but wholly-owned, subsidiary.
In making this recommendation, the MPUC relied upon
MPS's relatively small size, its isolation from the
rest of New England and concerns about the
Company's Canadian Subsidiary. The Plan further
stated that the MPUC would "periodically review
whether divestiture [of the Company's generation
assets] would be required".
* The T&D utilities would retain their ownership
interests in Maine Yankee, but would be required to
transfer the rights to the output to an affiliated
generation company. After 2005, BHE and CMP, but
not the Company, would be required to sell the
rights to the output to the highest bidder.
* All contracts between the utilities and any
qualifying facilities under PURPA will remain with
the T&D companies.
* The utilities should be provided a reasonable
opportunity to fully recover its generation-related
stranded costs. All of the Company's anticipated
stranded costs are generation-related.
-18-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
Because the MPUC's Recommended Plan does not have any
binding legal effect, this issue must ultimately be
resolved by the Maine Legislature. Many parties to this
proceeding have taken positions that vary substantially
from those set forth in this Plan and those parties can
be expected to advocate their positions before the
Legislature. The Company cannot, therefore, predict what
form the restructuring of Maine's electric utility
industry will ultimately take or what effect that
restructuring will have on the Company's business
operations or financial results.
(b) Multi-year Rate Plan is Approved for the Company by the
MPUC in Maine Public Service Company Re: Proposed
Increase in Retail Rates, MPUC Docket No. 95-052
On May 1, 1995, Maine Public Service Company filed with
the Maine Public Utilities Commission a proposed increase
in the rates it charges its retail customers. The
Company at the same time filed a five-year rate plan
requesting new rates beginning in January, 1996 as
detailed below. Reference is made to the Company's Form
10-Q for the quarter ended June 30, 1995 for a complete
description of the Company's filed rate plan.
After extensive negotiations, the Company, the MPUC Staff
and the Public Advocate filed a Stipulation with the
Commission on November 6, 1995, which established a four-
year rate plan for the Company. The one remaining party
to this proceeding, McCain Foods, Inc., opposed this
Stipulation. After a hearing on November 13, 1995, the
MPUC approved this Stipulation over the objection of
McCain Foods, Inc.
Under the terms of the Stipulation, the Company has the
right to receive the following increases:
January 1, 1996 4.4% $2.1 million
February 1, 1997 2.9% 1.4 million
February 1, 1998 2.75% 1.4 million
February 1, 1999 2.75% 1.4 million
-19-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
These increases will be subject to increases or decreases
resulting from the operation of the profit-sharing
mechanism, as well as the mandated costs and plant outage
provisions described below. The Company agreed that it
will seek no other increases, for either base or fuel
rates, except as provided under the terms of the rate
plan. There will be no fuel clause adjustments during
the term of the plan. The first two increases of 4.4%
and 2.9% became effective, as scheduled, on January 1,
1996 and February 1, 1997, respectively.
In 1995, the Company wrote off and will not collect in
retail rates the following amounts:
(a) $4,845,812, net of income taxes, of its
investment in Seabrook previously allocated to wholesale
sales.
(b) $1,390,000, net of income taxes, in other plant
investment, i.e. rate base, except transmission plant,
previously associated with the wholesale customers.
(c) $3,500,000 ($2,104,000, net of income taxes) in
deferred fuel.
The total amount of the write-offs, net of income taxes,
in 1995 were approximately $8,340,000, or approximately
$5.16 per share of common stock.
As a condition of the Stipulation, the Company requested
waivers for interest coverage tests under its revolving
credit arrangement and the Letter of Credit supporting
the public utility revenue bonds, 1991 series. Unless
these write-offs were considered extraordinary for
purposes of the interest coverage tests, the Company
would have been in violation of these interest coverage
tests. The waivers were received from the various
lenders prior to the MPUC's issuance of its order in this
proceeding.
-20-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
The Company will also be permitted to defer an amount of
$1.5 million annually of the costs of the Wheelabrator-
Sherman (WS) purchases over the term of the rate plan.
The approved rate plan provides that the Company can seek
recovery of this deferred amount (up to a total of $6
million) in rates beginning in the year 2001, after the
current term of the WS contract has expired. The Company
will further collect in rates and amortize over the four
years of the rate plan, $300,000, net of income taxes, in
deferred fuel with the remainder, approximately $1.3
million, net of income taxes, being deferred until the
year 2000, when rate recovery will be determined.
The approved rate plan further provides for the following
treatment of the Maine Yankee steam generator sleeving
costs: the Company will amortize its share of these
costs in equal amounts over a five-year period beginning
on January 1, 1996. At the expiration of the rate plan,
the remaining one-fifth of the costs will be amortized in
2000 subject to rate treatment at that time.
The approved rate plan contains a profit-sharing
mechanism based upon a target return of equity (ROE) of
11%, calculated according to retail ratemaking
mechanisms. This profit-sharing mechanism will apply
only to the last two rate increases scheduled to occur on
February 1, 1998 and February 1, 1999. As part of this
review process, the target ROE will be subject to
adjustment based on an index by averaging over a twelve-
month period the dividend yields on Moody's group of 24
electric utilities and Moody's utility bond yields. The
profit-sharing mechanism works as follows:
If the Company's ROE exceeds the target ROE by less than
300 basis points, this gain accrues entirely to
shareholders. Similarly, any deficiency of up to 300
basis points below the target ROE is borne entirely by
the shareholders.
All deficiencies of 300 or more basis points below the
target ROE will be shared equally by shareholders and
customers. All earnings of 300 or more basis points
above the target ROE must first be applied to reduce any
of deferred WS costs described above. Any remaining
excess earnings will be shared equally by customers and
shareholders.
-21-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
The plan also allows the Company to terminate the rate
plan and file for rate increases under traditional rate
application procedures if its earnings fall 500 or more
basis points below the target ROE during any twelve-month
period during the term of the plan.
The method agreed to by the parties for measuring earned
ROE for the purpose of the profit-sharing mechanism and
rate termination provision described above, allocates
various revenues and expenses between the wholesale and
retail jurisdictions using allocators that, in part,
reflect the Company's 1994 allocations. With the loss of
sales to Houlton Water Company in 1996, the Company
estimates that the use of the agreed-upon allocators will
produce a calculation of earnings for the profit-sharing
and termination mechanisms that could be as much as 400
basis points above the Company's actual financial ROE.
Because of this disparity, the Stipulation provides that
the agreed-upon allocation methodology will not apply if
the use of those allocators will require the Company to
write off any additional assets in accordance with
Generally Accepted Accounting Principles (GAAP). In that
event, the parties have agreed to develop a different
method for calculating profit-sharing and termination
that will not require the Company to write off any
additional assets.
The plan also provides that if either Maine Yankee or WS
cease operation for more than six months, the Company
shall be allowed to adjust its allowed rate increases by
50% of the net costs or net savings resulting from the
outage, together with any carrying costs on the balance
deferred. Any net costs or net savings during the first
six months of the outage would accrue entirely to
shareholders.
The plan further contains a mechanism for allocating the
savings resulting from any restructuring of the WS
contract during the term of the plan. Any savings would
be allocated first to the WS deferred costs accumulating
at $1.5 million annually, then to the deferred fuel
balance as of December 31, 1995 being deferred until
2000, next to eliminate any on-going WS deferrals and
finally, any savings that remain will be allocated 95% to
customers and 5% to shareholders.
-22-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
The plan provides that the Company can flow through to
customers at the time of the scheduled rate increases,
increases or decreases resulting from certain mandated
costs, such as tax or accounting changes, but not costs
resulting from natural disasters. To qualify, a mandated
cost must receive MPUC approval, must be beyond the
control of the Company's management, must effect the
Company specifically or the electric utility generally
and must exceed $300,000 in annual revenue requirements.
The Stipulation also provides for a number of accounting
orders. Among these are orders: permitting the Company
to amortize deferred post-retirement benefits other than
pension (SFAS 106) expenses in equal amounts over a ten-
year period beginning January 1, 1996, along with the
recovery of current year SFAS 106 costs; permitting the
Company to continue rate base treatment for unrecovered
plant costs and depreciation on the Caribou Steam Units
as well as the deferral and amortization over five years
of the reduction in force expenses (including pension
expenses under SFAS 88) resulting from the closing of
those units; and continued deferral and amortization of
replacement power and capacity costs associated with
Maine Yankee scheduled outages. Finally, the Stipulation
clarifies that the rate plan is not deregulation for
accounting purposes and provides for the continuing
recovery in rates of certain "regulatory assets", such as
the retail portion of the Company's Seabrook investment,
previously allowed by the MPUC.
On January 2, 1996, McCain Foods, Inc., which had
objected to the Stipulation, appealed the MPUC's approval
of the rate plan to the Maine Supreme Judicial Court.
This action was docketed as PUC 96-13. On March 20,
1996, the Company and McCain Foods filed with the
Commission a Power Purchase Agreement under which McCain
agreed to purchase all its electrical requirements from
the Company through 2000. On April 29, 1996, the MPUC
approved the Agreement and McCain dismissed its appeal
shortly thereafter.
In addition to the four-year rate plan, the MPUC, under
this docket, also approved the Company's proposal to
develop flexible rates to retain or attract new
customers. On October 23, 1995, the Company implemented
a reduced Rate AH for existing residential electric space
-23-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
heat. Customers who have a permanent electric space heat
system that supplies at least 50% of their heating
requirements have been offered a discount up to 40% from
October to April.
On November 27, 1995, the MPUC approved two new rates
that became effective December 1, 1995. The first, Rate
F, provides farmers with a discounted price for
electricity used in storage facilities, reducing their
winter electric rate ten percent from November through
March. The second, Rate EDR, an economic development
rate, provides a multi-year discount in the cost of
electric service for large commercial and industrial
customers who create new electrical load. This reduced
rate should encourage development in our electrical
service territory by providing an incentive rate while a
new business gets established or an existing business,
meeting certain criteria, completes expansion. Depending
on eligibility, the discount offered will range from 20%
the first year to 5% in the fourth year. After the four-
year period, EDR customers will be billed under the
Company's standard electric rates.
On January 21, 1997, the Company filed with the MPUC a
proposed reduced electric heat rate for new electric
space heating installations and a rebate program for
customers who purchase and use electric water heaters.
Both filings are pending before the MPUC.
(c) Peoples Heritage Bank v. Maine Public Service Company
U.S. District Court (D. ME) Civil Action No. 95-0180-B
On September 18, 1995, Peoples Heritage Bank filed
against the Company a civil action for declaratory and
monetary relief seeking recovery for response costs,
damages and attorneys fees incurred because of the
release of hazardous substance at a site in Presque Isle,
Maine. In 1992, Peoples Heritage purchased the property
and shortly thereafter discovered that the soil at the
site was contaminated with polychlorinated biphenyls
(PCBs) which it now alleges originated with two
electrical transformers placed on the site by the
Company. Peoples Heritage claims to have spent in excess
of $250,000 to remove the PCB contaminated soil and seeks
reimbursement of this amount.
-24-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
The suit was brought pursuant to the Comprehensive
Environmental Response, Compensation and Liability Act of
1980 (CERCLA), the Federal Declaratory Judgment Act and
under common law grounds of strict liability for
abnormally dangerous activities, negligence and trespass.
On December 2, 1996, the Court issued its judgment in
this proceeding for the Company and against Peoples
Heritage. The Court concluded that Peoples Heritage
failed to prove the Company had caused a release of a
hazardous substance at the site and credible expert
testimony pointed to other causes of contamination.
(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 1997.
The Company cannot predict the FERC's ultimate decision
in this matter.
(e) Maine Public Service Company, Proposed Increase in Rates
(Rate Design), MPUC Docket No. 95-052.
On June 15, 1995, the MPUC issued an order bifurcating
the Company's request for rate design from the revenue
requirement portion of this docket (see item (b) above).
Based upon marginal cost of service principles, the
Company had proposed a substantial redesign of its
current rates. For example, under the Company's proposed
rates for large industrial customers would have decreased
from their current level by nearly 8%, while rates for
-25-
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
residential customers would have increased by over 8%.
The Company's proposals were vigorously contested by the
MPUC Staff and the Public Advocate, who proposed only a
small decline for large industrial customers and a very
minor increase for residential. Hearings were held on
this matter before the MPUC on March 14 and 15, 1996.
On June 26, 1996, the MPUC issued its Order in this
matter. The MPUC found that, despite some infirmities in
the Company's supporting data, the Company was entitled
to a more substantial reallocation of its rates than
advocated by the MPUC Staff and Public Advocate. As a
result, rates for large industrial customers will
decrease by approximately 4.5%, while rates for
residential and commercial customers will increase by
approximately 1% and 3%, respectively. These changes
became effective June 29, 1996.
-26-
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 14, 1996, the only matter voted upon was the
uncontested election of the following directors to serve
until the 1999 Annual Meeting of Stockholders, each of
whom received the votes shown:
Non-votes and
Nominee For Against Abstentions
D. James Daigle 1,380,715 22,433 214,102
Deborah L. Gallant 1,374,834 28,314 214,102
G. Melvin Hovey 1,379,191 23,957 214,102
Walter M. Reed, Jr. 1,374,834 24,219 218,197
-27-
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, 1996, there were
1,619 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
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
1995
First Quarter $23-7/8 $20-5/8 $ .46 $ .46
Second Quarter $22-3/4 $19-7/8 .46 .46
Third Quarter $23-1/4 $21 .46 .46
Fourth Quarter $23-1/2 $20-5/8 .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 (1992-1996) is
included on page 12 of the Company's 1996 Annual Report to
Stockholders, which summary is incorporated herein by
reference.
-28-
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 3-11, Exhibit 13, 1996 Annual
Report to Shareholders, which pages are hereby incorporated
herein by reference. Information regarding "Construction" is
also furnished in Note 10, "Commitments and Contingencies", of
the Notes to the Consolidated Financial Statements, pages 25
to 27 of the 1996 Annual Report to Shareholders, which pages
are hereby incorporated herein by reference.
-29-
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 1996 Annual Report to
Stockholders on pages 13 through 27 and are incorporated
herein by reference:
Independent Auditors' Report.
Statements of Consolidated Operations for the years
ended December 31, 1996, 1995 and 1994.
Statements of Consolidated Cash Flows for the years
ended December 31, 1996, 1995 and 1994.
Consolidated Balance Sheets as of December 31, 1996
and 1995.
Statements of Consolidated Common Shareholders'
Equity for the years ended December 31, 1996, 1995
and 1994.
Consolidated Statements of Capitalization as of
December 31, 1996 and 1995.
Notes to Consolidated Financial Statements.
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, LLP,
(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
-30-
Form 10-K
Item 9. Changes In And Disagreements With Accountants On
Accounting and Financial Disclosure - Continued
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
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 either fiscal years 1995 or 1994 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
or any time thereafter has there been any disagreement between
the Company and the firm of Deloitte & Touche 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 or any time
thereafter did any event occur between the Company and
Deloitte & Touche that would require further reporting in this
Form 10-K.
At no time during the Company's two most recent fiscal years
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.
-31-
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 1997 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
1997 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 1997 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 1997 Annual Meeting of
Stockholders, which information is incorporated herein by
reference.
Item 13. Certain Relationships and Related Transactions
Not applicable.
-32-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K
(a) (1) Financial Statements
Independent Auditors' Report appears on page 44
of this Form 10-K.
Incorporated by reference into Part II of this
report from pages 13 through 27 of the 1996 Annual
Report to Stockholders:
Independent Auditors' Report.
Statements of Consolidated Operations for years
ended December 31, 1996, 1995 and 1994.
Statements of Consolidated Cash Flows for the years
ended December 31, 1996, 1995 and 1994.
Consolidated Balance Sheets as of December 31, 1996
and 1995.
Statements of Consolidated Common Shareholders'
Equity for the years ended December 31, 1996, 1995
and 1994.
Consolidated Statements of Capitalization as of
December 31, 1996 and 1995.
Notes to Consolidated Financial Statements.
(2) Financial Statement Schedules
Included in Part IV of this report:
-33-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
Page
Report of Independent Public Accountants 44
Schedule II - Valuation of Qualifying Accounts 45
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)
-34-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
4(g) Sixth Supplemental Indenture. (Exhibit A to
Form 8-K dated April 10, 1973)
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.
-35-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
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
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)
-36-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
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
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)
-37-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
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
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
-38-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
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
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,
-39-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
Fleet Bank of Maine, and The Bank of New York,
an agent for the participating Banks.
11 Not applicable.
12 Not applicable.
*13 1996 Annual Report to Shareholders.
*16 March 8, 1996 Letter regarding change in
certifying accountant from Deloitte & Touche
LLP
18 Not applicable.
19 Not applicable.
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).
-40-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
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).
99(i) Order (corrected) of the Maine Public
Utilities Commission dated December 5, 1990 in
Docket No. 87-167 (with attached Stipulation).
(Exhibit 28(l) to 1990 Form 10-K).
99(j) Order of the Federal Energy Regulatory
Commission Dated September 30, 1992 in Docket
No. ER92-774-000 and EL91-56-000. (Exhibit
28(k) to 1992 Form 10-K)
99(k) Order of the Federal Energy Regulatory
Commission dated December 11, 1992 in Docket
ER93-17-000. (Exhibit 28(l) to 1992 Form 10-
K)
99(l) 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(m) 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).
-41-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
*99(n) Order of Maine Public Utilities Commission
dated June 26, 1996 in Docket 95-052 (Rate
Design)
*99(o) December 31, 1996 Report and Recommended Plan
of Maine Public Utilities Commission Regarding
Electric Utility Restructuring, Docket No. 95-
462.
*99(p) Judgment of U.S. District Court (D. Me.) dated
December 2, 1996 in Peoples Heritage Bank v.
Maine Public Service Company, Civil Action No.
95-0180-B.
*99(q) Deloitte & Touche LLP's Report of Independent
Auditors dated February 14, 1996 regarding previous
years' audit opinions.
(b) A Form 8-K was filed on: July 25, 1996 under item 5,
Other Events; December 18, 1996, under item 5, Other
Events; December 23, 1996, under item 5, Other Events;
January 31, 1997, under item 5, Other Events; and
February 14, 1997, under item 5, Other Events.
A form 8-K/A was filed on March 14, 1996 under item 4,
Change in the Company's Certifying Accountant.
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 19th of March, 1997.
MAINE PUBLIC SERVICE COMPANY
By: /s/ Larry E. LaPlante
Larry E. LaPlante
Vice President, Finance,
Administration, and Treasurer
-42-
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. Melvin Hovey and Director 3/11/97
(G. Melvin Hovey)
/s/ Paul R. Cariani President and Director 3/8/97
(Paul R. Cariani)
/s/Robert E. Anderson Director 3/8/97
(Robert E. Anderson)
/s/ Donald F. Collins Director 3/7/97
(Donald F. Collins)
/s/ D. James Daigle Director 3/8/97
(D. James Daigle)
/s/ Richard G. Daigle Director 3/10/97
(Richard G. Daigle)
/s/ J. Gregory Freeman Director 3/13/97
(J. Gregory Freeman)
/s/ Deborah L. Gallant Director 3/10/97
(Deborah L. Gallant)
Director
(Nathan L. Grass)
/s/ J. Paul Levesque Director 3/10/97
(J. Paul Levesque)
/s/ Walter M. Reed, Jr Director 3/13/97
(Walter M. Reed, Jr.)
-43-
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, 1996, and for the year then
ended, which financial statements are included on pages 13 through 27 of
the 1996 Annual Report to Shareholders of Maine Public Service Company
and incorporated by reference herein. We have also audited the
financial statement schedule listed in the index on page 34 of this Form
10-K. These financial statements and financial statement schedule are
the responsibility of the Company's management. Our responsibility is
to express an opinion on these 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, 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, 1996,
and the consolidated results of their operations and their cash flows
for the year then ended in conformity with generally accepted accounting
principles. In addition, in our opinion, the financial statement
schedule 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.
Portland, Maine
February 11, 1997
-44-
Maine Public Service Company & Subsidiary
Valuation of Qualifying Accounts & Reserves
For the Years Ended December 31, 1996, 1995, & 1994
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:
1996 214,130 182,000 102,627 291,728 207,029
1995 214,215 150,800 109,390 260,275 214,130
1994 214,329 119,000 164,999 284,113 214,215
-45-
Exhibit 10(t)
THIS INSTRUMENT GRANTS A SECURITY INTEREST
BY A TRANSMITTING UTILITY
THIS INSTRUMENT CONTAINS AFTER-ACQUIRED PROPERTY PROVISIONS
MAINE PUBLIC SERVICE COMPANY
TO
IBJ SCHRODER BANK
& TRUST COMPANY
Trustee
THIRD SUPPLEMENTAL INDENTURE
Dated as of June 1, 1996
Supplementing Indenture of Second Mortgage and
Deed of Trust dated as of October 1, 1985
and
Relating to an Issue of Second Mortgage and
Collateral Trust Bonds, Series Due 2002
This is a Security Agreement granting a Security Interest
in Personal Property, Including Personal Property affixed to
Realty as well as a Mortgage
upon Real Estate and other Property.
THIS THIRD SUPPLEMENTAL INDENTURE (hereinafter called the "Third
Supplemental Indenture"), dated as of June 1, 1996, made by MAINE PUBLIC
SERVICE COMPANY, a Maine corporation (hereinafter called the "Company"),
party of the first part, and IBJ SCHRODER BANK & TRUST COMPANY (as successor
to J. Henry Schroder Bank & Trust Company), a banking corporation duly
organized and existing under the laws of the State of New York, and having
its principal place of business in the City of New York, State of New York
(hereinafter called the "Trustee"), party of the second part.
WHEREAS, the Company has heretofore executed and delivered to the
Trustee an Indenture of Second Mortgage and Deed of Trust, dated as of
October 1, 1985 (hereinafter called the "Original Indenture"), to secure the
payment of principal and interest on, as provided therein, its bonds (in the
Original Indenture and herein called the "Bonds") to be designated generally
as its "Second Mortgage and Collateral Trust Bonds", and to be issued in one
or more series as provided in the Original Indenture, pursuant to which the
Company provided for the creation of the Bonds of the initial series, known
as Second Mortgage and Collateral Trust Bonds, Floating Rate Series A due
1987 (herein sometimes called "Bonds of the 1987 Series"), Second Mortgage
and Collateral Trust Bonds, 14% Series due 1990 (herein sometimes called
"Bond of the 1990 Series") and Second Mortgage and Collateral Trust Bonds,
9 7/8% Series due 1995 (herein sometimes called "Bonds of the 1995 Series"
and together with the Bonds of the 1987 Series and the Bonds of the 1990
Series, called collectively the "Bonds of the Initial Series"); and
WHEREAS, the Company has heretofore executed and delivered to the
Trustee a First Supplemental Indenture, dated as of March 1, 1991, pursuant
to which the Company supplemented and modified the Original Indenture and
provided for the creation of a fourth series of Bonds designated as "Second
Mortgage and Collateral Trust Bonds, Series due 1996" (herein sometimes
called "Bonds of the 1996 Series"); and
WHEREAS, the Company has heretofore executed and delivered to the
Trustee a Second Supplemental Indenture, dated as of September 1, 1991,
pursuant to which the Company supplemented the Original Indenture, as
supplemented and modified, and provided for the creation of a fifth series
of Bonds designated as "Second Mortgage and Collateral Trust Bonds, 9.60%
Series due 2001" (herein sometimes called "Bonds of the 2001 Series"); and
WHEREAS, pursuant to the Original Indenture, as so supplemented and
modified, there have been executed, authenticated and delivered and there are
now outstanding Second Mortgage and Collateral Trust Bonds of Series and in
principal amounts as follows:
Issued Outstanding
Bonds of the 2001 Series $7,500,000 $7,500,000
which constitute the only Bonds outstanding under the Original Indenture, as
so supplemented and modified; and
WHEREAS, the Company now desires to create a new series of Bonds to be
designated Second Mortgage and Collateral Trust Bonds, Series due 2002
(herein sometimes called the "Bonds of the 2002 Series"), and the Original
Indenture provides that each series of Bonds (except the Bonds of the Initial
Series) shall be created by an indenture supplemental to the Original
Indenture; and
WHEREAS, the Original Indenture further provides that all property of
the character specifically described in the Original Indenture, and all
improvements, extensions, betterments or additions to the property
specifically described in the Original Indenture, constructed or acquired
after the date of the execution and delivery of the Original Indenture, shall
be and become subject to the lien of the Original Indenture, and that the
Company shall from time to time execute, acknowledge and deliver any and all
such further assurances, conveyances, mortgages or assignments of such
property as may be required by the terms and provisions of the Original
Indenture, or as the Trustee under the Original Indenture may require, and
the Company now desires to subject to the lien of the Original Indenture
certain additional properties which it has constructed or acquired since the
date of execution and delivery of the Second Supplemental Indenture; and
WHEREAS, all acts and proceedings required by law and by the charter and
by-laws of the Company necessary to make the Bonds of the 2002 Series to be
initially issued when executed by the Company, authenticated and delivered
by the Trustee and duly issued, the valid, binding and legal obligations of
the Company, and to constitute the Original Indenture, as heretofore
supplemented and modified and as supplemented and modified by this Third
Supplemental Indenture, a valid and binding mortgage and deed of trust,
subject to permitted encumbrances including the lien of the Indenture of
First Mortgage (each as defined in the Original Indenture), for the security
of the Bonds, in accordance with the terms of the Original Indenture, as so
supplemented and modified, and the terms of the Bonds, have been done and
taken; and the execution and delivery of this Third Supplemental Indenture
and the issue of the Bonds of the 2002 Series to be initially issued have
been in all respects duly authorized;
NOW, THEREFORE, for the purposes aforesaid and in pursuance of the terms
and provisions of the Original Indenture, the Company has executed and
delivered this Third Supplemental Indenture (the Original Indenture, as
supplemented and modified by the First Supplemental Indenture, and
supplemented by the Second Supplemental Indenture and as supplemented and
modified by this Third Supplemental Indenture and any and all supplemental
indentures hereafter entered into between the Company and the Trustee in
accordance with the provisions of the Original Indenture, as supplemented and
modified, being herein sometimes called the "Indenture"), and in
consideration of the sum of One Dollar ($1.00) to the Company duly paid by
the Trustee at or before the ensealing and delivery hereof, and for other
good and valuable considerations, the receipt whereof is hereby acknowledged,
the Company hereby covenants to and with the Trustee and its successors in
the trusts under the Original Indenture, as supplemented and modified, as
follows:
ARTICLE ONE
Schedule of Mortgaged Property.
SECTION 1.01. In order further to secure the payment of the principal
of, premium, of any, and interest on, all Bonds at any time issued and
outstanding under the Indenture, according to their tenor, purport and
effect, and further to secure the performance and observance of all the
covenants and conditions in said Bonds and in the Original Indenture, as
supplemented and modified, and in this Third Supplemental Indenture
contained, for the considerations above expressed, and for and in
consideration of the mutual covenants herein contained and of the purchase
and acceptance of the Bonds by holders thereof, the Company has executed and
delivered this Third Supplemental Indenture and by these presents does grant,
bargain, sell, alien, remise, release, convey, assign, transfer, mortgage,
pledge, set over and confirm unto IBJ Schroder Bank & Trust Company, as
Trustee under the Indenture, and to its assigns forever, all property, real,
personal or mixed, acquired since the execution and delivery of the Second
Supplemental Indenture which by the terms of the Original Indenture, as
supplemented and modified, is subject or is intended to be subject to the
lien of the Indenture, including without limiting the generality of the
foregoing, the following described property:
CLAUSE I
PART I
AROOSTOOK COUNTY, MAINE
(1) A certain piece or parcel of real estate in said Ashland, bounded
and described as follows, to wit: Beginning at the Northeast corner of a
plot of land owned by George Allen adjacent to the Sheridan Road, so called,
thence along the northerly property line N71 degrees-28'W distant 165 feet
more or less to the northwest corner of the said plot of land; thence along the
westerly property line approximately S18 degrees-32'W distant 100 feet more
or less; thence S71 degrees-28'E distant 165 feet more or less to the westerly
boundary of the Sheridan Road, so called; thence approximately N18 degrees-
32'E along the easterly boundary of the said plot of land distant 100 feet
more or less to the point of beginning.
Recorded in the Southern District of the Aroostook Registry of Deeds in
Volume 2534, page 56 on January 21, 1993.
(2) A certain piece or parcel of land situated in the Town of Ashland,
in the County of Aroostook and State of Maine, being a one hundred (100) foot
wide strip of land easterly of and contiguous to an existing right-of-way now
or formerly owned by Maine Public Service Company as recorded in the Southern
District of the Aroostook Registry of Deeds in Vol. 1126, Page 264, said one
hundred (100) foot wide strip of land extends from the northerly line of a
parcel of land now or formerly owned by Maine Public Service Company as
recorded in said Registry in Vol. 1124, Page 17, to the northerly line of Lot
14, said strip being a part of Lot No. 14, also being part of the land now
or formerly owned by Carlton L. and Catherine E. Jimmo, as recorded in Vol.
1036, Page 374, in said Registry, bounded and described more particularly as
follows, to wit:
Beginning at a 1/2" diameter metal pipe found at the northeasterly
corner of a parcel of land now or formerly owned by Maine Public Service
Company as recorded in Vol. 1124, Page 17; thence along the northerly line
of Vol. 1124, Page 17 a magnetic bearing of North seventy-one degrees thirty-
five minutes zero zero seconds west (N 71 degrees 35' 00" W) a distance of
fifty-eight and fifty-two hundredths (58.52) feet to the southeasterly corner
of a parcel of land now or formerly owned by Maine Public Service Company as
recorded in said Registry in Vol. 1126, Page 264; thence along the easterly
line of Vol. 1126, Page 264 north eighteen degrees zero five minutes fifteen
seconds east (N 18 degrees 05' 15" E) a distance of one thousand seventy-eight
and eight-one hundredths (1078.81) feet to the northerly line of Lot 14;
thence along the northerly line of Lot 14 and remains of a cedar rail fence
south seventy-one degrees fifty-four minutes forty-five seconds east (S 71
degrees 54' 45"E) a distance of one hundred (100) feet to a rebar set in a
cedar rail; thence parallel with the easterly line of Vol. 1126, Page 264
south eighteen degrees zero five minutes fifteen seconds west (S 18 degrees
05' 15" W) a distance of one thousand seventy-nine and thirty-eight hundredths
(1079.38) feet to a rebar set; thence north seventy-one degrees thirty-five
minutes zero zero seconds west (N 71 degrees 35' 00" W) a distance of forty-
one and forty-eight hundredths (41.48) feet to the point of beginning, the
last two courses being across the source parcel, the above described parcel
of land containing two and forty-eight hundredths acres (2.48).
The above described piece of land is based on a field survey conducted
under the supervision of Daniel O. Bridgeham, P.L.S. #1027, and shown on a
Plat dated March 31, 1992. All bearings are magnetic as of March, 1992. All
monuments set were 5/8" metal rebar with yellow plastic caps affixed to them,
with Daniel O. Bridgham, P.L.S. #1027: imprinted on the caps.
Recorded in the Southern District of the Aroostook Registry of Deeds in
Volume 2476, page 152 on June 30, 1992.
(3) The following described piece or parcel of real estate being a part
of Section 11, Lot Number Four (4) in the City of Presque Isle, formerly
Maysville, County of Aroostook and State of Maine, and being more
particularly bounded and described as follows, to wit:
Commencing at a point on the easterly right-of-way of the Parkhurst Siding
Road, so-called, at the northwest corner of a parcel of land conveyed to
Maine Public Service Company by Warranty Deed recorded at the Southern
Aroostook Registry of Deeds in Volume 630, Page 286; thence along the
easterly right-of-way of said Parkhurst Siding road, along a 1,000 foot
radius curve to the right with a delta of 20-36-48, an arc distance of three
hundred fifty-nine and seventy-seven thousandths (359.77) feet to a point;
thence north seventeen degrees thirty-three minutes ten seconds east (N 17
degrees 33' 10" E) a distance of one hundred fifty-four and sixty-two
thousandths (154.62) feet to a 5/8" rebar set which rebar marks the point of
beginning of the real estate conveyed herein; thence south sixty-eight degrees
thirty minutes eighteen seconds east (S 68 degrees 30' 18" E) a distance of one
hundred thirteen and nine tenths (113.9) feet to a 5/8" iron rebar set; thence
north twenty-one degrees twenty-nine minutes twenty-two seconds east (N 21
degrees 29' 22" E) a distance of two hundred (200) feet to a 5/8" iron rebar
set; thence north sixty-eight degrees thirty minutes thirty-eight seconds west
(N 68 degrees 30' 38" W) a distance of one hundred fifteen and fifty-five
thousandths (115.55) feet to a 5/8" iron rebar set on the easterly line of the
right-of-way of said Parkhurst Siding Road; thence in a parallel southerly
direction along the easterly margin of said Parkhurst Siding Road a distance of
two hundred (200) feet, more or less, to the iron rebar set marking the point
of beginning of the real estate conveyed herein.
Recorded in the Southern District of the Aroostook Registry of Deeds in
Volume 2412, Page 144 on November 20, 1991.
PENOBSCOT COUNTY, MAINE
(1) Beginning on the westerly Right of Way limit of State Highway "320"
(Rte. 11) Federal Aid Project No. S-0320 (2), Patten, Penobscot County,
Maine, at a monument located at Station 130 + 00; thence N28 degrees 13'E
along said westerly Right of Way limit to the Eastern Maine Electric property
line distant 89.2 feet; thence N61 degrees 47'W distant 172'; thence, N28
degrees 13'E distant 100 feet; thence, S61 degrees 47'E distant 160 feet;
thence N28 degrees 13'E distant 10 feet; thence N61 degrees 47'W distant 170
feet; thence S28 degrees 13'W distant 120'; thence S61 degrees 47'E distant 10
feet; thence, S28 degrees 13'W distant 115 feet; thence S61 degrees 47'E
distant 172 feet; thence N 28 degrees 13'E distant 35.8 feet and point of
beginning. All bearings are magnetic 1963.
Being a portion of Lot #37 according to the original plan of the Town of
Patten, Maine, recorded in Plan Book 2, Page 6 of the Penobscot County
Registry of Deeds.
Recorded in the Penobscot Registry of Deeds in Volume 4920, Page 5 on
September 13, 1991.
PART II
TRANSMISSION LINES
RIGHT-OF-WAY, THE HOULTON TO ISLAND FALLS LINE, SO CALLED
A 44,000 volt transmission line in Aroostook County, Maine owned
and operated by Maine Public Service Company from Houlton to Island Falls,
a distance of approximately 27.85 miles, said Maine Public Service Company
line being constructed for the most part on rights-of-way conveyed to Maine
Public Service Company by the following deeds:
Recorded
Grantor Date Vol. Page Registry at:
Emery W & Norma Nightingale 3/11/94 2662 47 Houlton
Katahdin Forest Products 7/18/94 2704 294 Houlton
Katahdin Development Corp 12/5/94 2746 346 Houlton
Daniel E. Russell 3/14/94 2662 338 Houlton
Est. of Chester A. Shorey 3/31/94 2667 282 Houlton
Rodney V. Anderson 4/01/94 2668 80 Houlton
Herbert C. Haynes, Inc. 3/24/94 2665 162 Houlton
RIGHT-OF-WAY, AEI TRANSMISSION LINE, SO CALLED
A 69,000 volt transmission line in Aroostook County, Maine owned and
operated by Maine Public Service Company from AEI generating plant in Ashland
to Maine Public Service substation in Ashland, a distance of approximately
2.69 miles, said Maine Public Service Company line being constructed for the
most part on rights-of-way conveyed to Maine Public Service Company by the
following deeds:
Recorded
Grantor Date Vol. Page Registry at:
Myron Turner 8/04/92 2487 25-27 Houlton
Francis Jimmo, Jr.
& Gail Jimmo 8/04/92 2487 22-24 Houlton
T. Robert Graham 8/04/92 2487 19-21 Houlton
Roger Hews & Shirley M. Hews 8/17/92 2490 15-17 Houlton
Ashland Water & Sewer Dist. 8/20/92 2490 318-320 Houlton
RIGHT-OF-WAY, GNP CHIPPER, SO CALLED
A 34,500 volt transmission line in Aroostook County, Maine owned and
operated by Maine Public Service Company from GNP Plant in Portage to Maine
Public Service substation in Portage, a distance of approximately .744 miles,
said Maine Public Service Company line being constructed for the most part
on rights-of-way conveyed to Maine Public Service Company by the following
deeds:
Recorded
Grantor Date Vol. Page Registry at:
Great Norther Paper Company 5/25/94 2686 302 Houlton
RIGHT-OF-WAY, PRESQUE ISLE MALL, SO CALLED
A 69,000 volt transmission line in Aroostook County, Maine owned and
operated by Maine Public Service Company from Maysville Ave, Presque Isle to
corner of Carmichael Street and Maysville Ave., a distance of approximately
.289 miles, said Maine Public Service Company line being constructed for the
most part on rights-of-way conveyed to Maine Public Service Company by the
following deeds:
Recorded
Grantor Date Vol. Page Registry at:
Maine Potato Growers 7/29/91 2381 108 Houlton
New England Telephone Co. 3/05/92 2434 166 Houlton
Widewater Aroostook Centre 3/16/94 2669 20-24 Houlton
The foregoing rights-of-way are conveyed subject to reservations,
conditions, restrictions, limitations and exceptions referred to or mentioned
in the deeds above listed.
CLAUSE II
All and singular the lands, real estate, chattels real, interests in
land, leaseholds, ways, rights-of-way, easements, servitudes, permits and
licenses, lands under water, riparian rights, franchises, privileges, rights
and interests, electric generating plants, power houses, dams, stations,
electric transmission and distribution systems, substations, conduits, poles,
wires, cables, office buildings, warehouses, garages, machine shops, and
other buildings and structures, implements, meters, tools, and other
apparatus, appurtenances and facilities materials and supplies and all other
property of any nature appertaining to any of the plants, systems, business
or operations of the Company, whether or not affixed to the realty, used in
the operation of any of the premises or plants or systems or otherwise, which
are now owned, or which may hereafter be owned or acquired by the Company,
other than excepted property as hereinafter defined.
CLAUSE III
All corporate Federal, State, municipal and other permits, consents,
licenses, bridge licenses, bridge rights, river permits, franchises, grants,
privileges and immunities of every kind and description, now belonging to or
which may hereafter be owned, held, possessed or enjoyed by the Company
(other than excepted property as hereinafter defined) and all renewals,
extensions, enlargements and modifications of any of them.
CLAUSE IV
Also all other property, real, personal or mixed, tangible or intangible
(other than excepted property as hereinafter defined) of every kind,
character and description and wheresoever situated, whether or not useful in
the generation, manufacture, production, transportation, distribution, sale
or supplying electricity now owned or which may hereafter be acquired by the
Company, it being the intention hereof that all property, rights and
franchises acquired by the Company after the date of the execution and
delivery hereof (other than excepted property as hereinafter defined) shall
be as fully embraced within and subjected to the lien of the Indenture as if
such property were now owned by the Company and were specifically described
herein and conveyed hereby.
CLAUSE V
Together with (other than excepted property as hereinafter defined) all
and singular the plants, buildings, improvements, additions, tenements,
hereditaments, easements, rights, privileges, licenses and franchises and all
other appurtenances whatsoever belonging or in any wise appertaining to any
of the property hereby mortgaged or pledged, or intended so to be, or any
part thereof, and the reversion and reversion, remainder and remainders, and
the rents, revenues, issues, earnings, income, products and profits thereof,
and every part and parcel thereof, and all the estate, rights, title,
interest, property, claim and demand of every nature whatsoever of the
Company at law, in equity or otherwise howsoever, in, of and to such property
and every part and parcel thereof.
CLAUSE VI
Also any and all property, real, personal or mixed, including excepted
property, that may, from time to time hereafter, by delivery or by writing
of any kind, for the purposes of the Indenture be in any wise subjected to
the lien of the Indenture or be expressly conveyed, mortgaged, assigned,
transferred, deposited and/or pledged by the Company, or by anyone in its
behalf or with its consent, to and with the Trustee, which is hereby
authorized to receive the same at any and all times as and for additional
security and also, when and as provided in the Indenture, to the extent
permitted by law. Such conveyance, mortgage, assignment, transfer, deposit
and/or pledge or other creation of lien by the Company, or by anyone in its
behalf, or with its consent, of or upon any property as and for additional
security may be made subject to any reservations, limitations, conditions and
provisions which shall be set forth in an instrument or agreement in writing
executed by the Company or the person or corporation conveying, assigning,
mortgaging, transferring, depositing and/or pledging the same and/or by the
Trustee, respecting the use, management and disposition of the property so
conveyed, assigned, mortgaged, transferred, deposited and/or pledged, or the
proceeds thereof.
CLAUSE VII
There is however, expressly excepted and excluded from the lien and
operation of the Indenture the following described property of the Company,
herein sometimes referred to as "excepted property":
(a) Any and all property expressly excepted and excluded from
the Original Indenture and from the lien and operation thereof by
Paragraph A of Clause XI of the Granting Clauses thereof and all
property of the character expressly excepted or intended to be
excepted and excluded by Paragraphs B through I of said Clause XI;
and
(b) All property which prior to the execution and delivery
of this Third Supplemental Indenture has been released by the
Trustee or otherwise disposed of by the Company free from the lien
of the Indenture, in accordance with the provisions thereof.
The Company may, however, pursuant to the provisions of Granting Clause
VI above, subject to the lien and operation of the Indenture all or any part
of the excepted property.
TO HAVE AND TO HOLD the trust estate and all and singular the lands,
properties, estates, rights, franchises, privileges and appurtenances hereby
mortgaged, conveyed, pledged or assigned, or intended so to be, together with
all the appurtenances thereto appertaining and the rents, issues and profits
thereof, unto the Trustee and its successors in trust and to its assigns,
forever:
SUBJECT, HOWEVER, to the exceptions, reservations, restrictions,
conditions, limitations, covenants and matters recited in Schedule A to the
Original Indenture or otherwise recited in the Original Indenture, as
modified and supplemented, and contained in all deeds and other instruments
whereunder the Company has acquired any of the property now owned by it, and
to permitted encumbrances as defined in Subsection B of Section 1.11 of the
Original Indenture, and, with respect to any property which the Company may
hereafter acquire, to all terms, conditions, agreements, covenants,
exceptions and reservations expressed or provided in the deeds or other
instruments, respectively, under any by virtue of which the Company shall
hereafter acquire the same and to any liens thereon existing, and to any
liens for unpaid portions of the purchase money placed thereon, at the time
of acquisition;
BUT IN TRUST, NEVERTHELESS, for the equal and proportionate use,
benefit, security and protection of those who from time to time shall hold
the Bonds authenticated and delivered under the Indenture and duly issued by
the Company, without any discrimination, preference or priority of any one
Bond over any other by reason of priority in the time of issue, sale or
negotiation thereof or otherwise, except as provided in Section 12.28 of the
Original Indenture, so that, subject to said Section 12.28, each and all of
said Bonds shall have the same right, lien and privilege under the Indenture,
and shall be equally secured hereby (except in so far as any sinking fund,
replacement fund or other fund established in accordance with the provisions
of the Indenture may afford additional security for the Bonds of any specific
series) and shall have the same proportionate interest and share in the trust
estate, with the same effect as if all of the Bonds had been issued, sold and
negotiated simultaneously on the date of the delivery hereof;
AND UPON THE TRUSTS, USES AND PURPOSES and subject to the covenants,
agreements and conditions in the Indenture set forth and declared.
ARTICLE TWO
Bonds of the 2002 Series and Certain
Provisions Relating Thereto
Section 2.01. Terms of the Bonds of the 2002 Series. There shall be
a series of Bonds, known as and entitled "Second Mortgage and Collateral
Trust Bonds, Series Due 2002" (herein referred to as the "Bonds of the 2002
Series"), and the form thereof shall be substantially as hereinafter set
forth in Section 2.02.
The Bonds of the 2002 Series shall be issued to The Bank of New York,
as Agent, to secure the obligations of the Company under a Letter of Credit
and Reimbursement Agreement, dated as of June 1, 1996, among the Company, The
Bank of New York ("BNY") and Fleet Bank of Maine ("Fleet") and The Bank of
New York, as Agent (in such capacity, "BNY Agent"), and as Issuing Bank (in
such capacity, "BNY Issuing Bank") (the "Reimbursement Agreement"), pursuant
to which BNY Issuing Bank has issued its irrevocable, transferrable, direct-
pay letter of credit (the "Letter of Credit") to support certain Maine Public
Utility Financing Bank Public Utility Refunding Revenue Bonds, Series 1996
(Maine Public Service Company Project) (the "Revenue Bonds").
The aggregate principal amount of the Bonds of the 2002 Series which may
be authenticated and delivered and outstanding under this Third Supplemental
Indenture shall be limited to $15,875,000 except for duplicate Bonds,
authenticated and delivered pursuant to Section 2.12 of the Original
Indenture. The definitive Bonds of the 2002 Series shall be issued only as
registered Bonds without coupons of the denomination of $1.00 and of any
multiple thereof and shall be registered in the name of BNY Agent.
The date of authentication on the original issuance of the Bonds of the
2002 Series shall be the date of commencement of the first interest period
for such Bonds. All Bonds of the 2002 Series shall mature June 19, 2002, and
shall bear interest at the Default Rate set forth in, and in accordance with,
the Reimbursement Agreement until the payment of the principal thereof. Both
principal of and interest on the Bonds of the 2002 Series will be paid in any
coin or currency of the United States of America which at the time of payment
is legal tender for the payment of public and private debts, at the principal
office in the City of New York, New York, of the Trustee or, at the office
of its successor as Trustee.
The definitive Bonds of the 2002 Series may be issued in the form of
Bonds engraved, printed or lithographed on steel engraved borders. Bonds of
the 2002 Series may also be issued as temporary printed, lithographed or
typewritten Bonds, and, so long as the registered holder of such Bonds does
not request their exchange for Bonds in definitive form, the Company shall
not be deemed to have unreasonably delayed the preparation, execution and
delivery of definitive Bonds as called for by Section 2.08 of the Original
Indenture.
Every Bond of the 2002 Series shall be dated as provided in Section 2.05
of the Original Indenture except that upon original issuance of the Bonds of
the 2002 Series, the Bonds of the 2002 Series shall be dated the date of
authentication.
The Bonds of the 2002 Series shall be nontransferable prior to maturity
except upon the prior written consent of the Company or to effect transfer
to any successor or assignee of BNY Agent if and to the extent that BNY Agent
shall have assigned its rights under the Reimbursement Agreement, any such
transfer to be made at the principal corporate trust office of the Trustee
in the City of New York, New York, upon surrender and cancellation of such
Bonds of the 2002 Series, accompanied by a written instrument of transfer in
a form approved by the Company, duly executed by the registered owner of such
Bonds of the 2002 Series or by his duly authorized attorney, and thereupon
a new Bond of the 2002 Series, for a like principal amount, will be issued
to the successor or assignee of BNY Agent, in exchange therefor.
The Trustee hereunder shall, by virtue of its office as such Trustee,
be the registrar and transfer agent of the Company for the purpose of
registering and transferring Bonds of the 2002 Series.
Section 2.02. Form of Bonds of the 2002 Series. The text of the Bonds
of the 2002 Series and the Trustee's authentication certificate to be
executed on the Bonds of said series, shall be in substantially the following
forms, respectively.
[FORM OF FACE OF BOND OF THE 2002 SERIES]
No. R $_____________
MAINE PUBLIC SERVICE COMPANY
Second Mortgage and Collateral Trust Bond,
Series due 2002
Due June 19, 2002
MAINE PUBLIC SERVICE COMPANY, a Maine corporation (hereinafter sometimes
called the "Company"), for value received, hereby promises to pay to ________
___________________________________ or registered assigns,___________________
________________ Dollars on June 19, 2002, and to pay to the registered owner
hereof interest thereon from the date hereof at the Default Rate set forth
in, and in accordance with, the Reimbursement Agreement referred to below
until payment of the principal hereof.
The Bonds of the 2002 Series, including this bond, are issued to secure
the obligations of the Company under a Letter of Credit and Reimbursement
Agreement, dated as of June 1, 1996 (the "Reimbursement Agreement") among the
Company, The Bank of New York ("BNY") and Fleet Bank of Maine ("Fleet") and
The Bank of New York, as Agent (in such capacity, "BNY Agent") and as Issuing
Bank (in such capacity, "BNY Issuing Bank"), pursuant to which BNY Issuing
Bank has issued its irrevocable, transferrable, direct-pay letter of credit
(the "Letter of Credit") to support certain Maine Public Utility Financing
Bank Public Utility Refunding Revenue Bonds, Series 1996 (Maine Public
Service Company Project) (the "Revenue Bonds").
The obligation of the Company to make any payment of interest on the
Bonds of the 2002 Series, when such interest shall be due and payable, shall
be deemed to be, and shall be, satisfied and discharged if the Company shall
have paid all interest under the Reimbursement Agreement then due and
payable. The obligation of the Company to make payments with respect to the
principal of Bond of the 2002 Series at any time shall be deemed to be, and
shall be, satisfied and discharged if, at any time that such payment of
principal shall be due, the Company shall have paid for all amounts then due
pursuant to Sections 2.03 and 2.04 of the Reimbursement Agreement.
The principal of and interest on this bond will be paid in any coin or
currency of the United States of America which at the time of payment is
legal tender for the payment of public and private debts at the principal
office in the City of New York, New York, of the Trustee under the Indenture
mentioned on the reverse hereof. Interest on this bond will be payable at
the Corporate Trust office in the City of New York, New York, of the Trustee
provided, however, that interest on this bond shall, unless otherwise
directed by the registered holder hereof, be paid by check payable to the
order of the registered holder entitled thereto and mailed by the Trustee by
first class mail, postage prepaid, to such holder at his address as shown on
the bond register for the bonds in this series.
This bond shall not become or be valid or obligatory for any purpose
until the authentication certificate hereon shall have been signed by the
Trustee.
The provisions of this bond are continued on the reverse hereof and such
continued provisions shall for all purposes have the same effect as though
fully set forth at this place.
IN WITNESS WHEREOF, MAINE PUBLIC SERVICE COMPANY has caused these
presents to be executed in its name and behalf of its President or one of its
Vice Presidents and its corporate seal or a facsimile thereof to be affixed
hereto and attested by its Secretary or one of its Assistant Secretaries, all
as of __________, 19__.
MAINE PUBLIC SERVICE COMPANY
By: ___________________________________
Vice President
Attest:
__________________________________________
Secretary
[FORM OF REVERSE OF BOND OF THE 2002 SERIES]
This bond constitutes the entire series designated as Bonds of the
2002 Series, of an authorized issue of bonds of the Company, known as Second
Mortgage and Collateral Trust Bonds, issued under and secured by an Indenture
of Second Mortgage and Deed of Trust dated as of October 1, 1985, duly
executed and delivered by the Company to IBJ Schroder Bank & Trust Company,
as Trustee, to which Indenture of Second Mortgage and Deed of Trust as
supplemented and modified by indentures supplemental thereto, including a
Third Supplemental Indenture dated as of June 1, 1996, duly executed by the
Company to said Trustee and all indentures supplemental thereto (herein
sometimes collectively called the "Indenture") reference is hereby made for
a description of the property mortgaged and pledged as security for said
bonds, the nature and extent of the security, and the rights, duties and
immunities thereunder of the Trustee, the rights of the holders of said bonds
and of the Trustee and of the Company in respect of such security, and the
terms upon which said bonds may be issued thereunder.
This bond shall be subject to redemption as a whole or in part, at any
time, at the option of the Company prior to maturity upon payment of the
principal amount thereof in the manner provided for the Indenture. In the
event that the Revenue Bonds outstanding under the Indenture of Trust, dated
as of June 1, 1996, between the Maine Public Utility Financing Bank and Fleet
National Bank (the "Revenue Bond Indenture") shall become immediately due and
payable pursuant to Section 9.01(e) or 9.01(f) of the Revenue Bond Indenture,
this bond shall be redeemed by the Company, on the date such Revenue Bonds
shall have become immediately due and payable, at the principal amount hereof
plus unpaid interest accrued to the date of redemption.
Any redemption pursuant to the preceding paragraph shall be made upon
prior notice given by first class mail, postage prepaid, as provided in the
Indenture to the holders of record of each bond affected not less than thirty
days nor more than ninety days prior to the redemption date and subject to
all other conditions and provisions of the Indenture.
If this bond is duly called for redemption and payment duly provided for
as specified in the Indenture, this bond shall cease to be entitled to the
lien of the Indenture from and after the date payment is so provided for and
shall cease to bear interest from and after the redemption date.
The Company and the Trustee and any paying agent may deem and treat the
person in whose name this bond shall be registered upon the bond register for
the bonds of this series as the absolute owner of such bond for the purpose
of receiving payment of or on account of the principal of and interest on
this bond and for all other purposes, whether or not this bond be overdue;
and all such payments so made to such registered holder or upon his order
shall be valid and effectual to satisfy and discharge the liability upon this
bond to the extent of the sum or sums so paid and neither the Company nor the
Trustee nor any paying agent shall be affected by any notice to the contrary.
This bond is nontransferable prior to its maturity except upon the prior
written consent of the Company or to effect transfer to any successor or
assignee of BNY Agent if and to the extent that BNY Agent shall have assigned
its rights under the Reimbursement Agreement, any such transfer to be made
at the principal corporate trust office of the Trustee in the City of New
York, New York, upon surrender and cancellation of this bond, accompanied by
a written instrument of transfer in a form approved by the Company, duly
executed by the registered owner of this bond or by his duly authorized
attorney, and thereupon a new bond of this series, for a like principal
amount, will be issued to the successor or assignee of BNY Agent in exchange
therefor, as provided in the Indenture.
If a default as defined in the Indenture shall occur, the principal of
this bond may become or be declared due and payable before maturity in the
manner and with the effect provided in the Indenture. The holders, however,
of certain specified percentages of the bonds at the time outstanding,
including in certain cases specific percentages of bonds of particular
series, may in the cases, to the extent and under the conditions provided in
the Indenture, waive past defaults thereunder and the consequences of such
defaults.
No recourse shall be had for the payment of the principal of or the
interest on this bond, or for any claim based hereon, or otherwise in respect
hereof or of the Indenture, against any incorporator, stockholder, director
or officer, past, present or future, as such, of the Company or of any
predecessor or successor corporation, either directly or through the Company
or such predecessor or successor corporation, under any constitution or
statute or rule of law, or by the enforcement of any assessment or penalty,
or otherwise, all such liability of incorporators, stockholders, directors
and officers, as such, being waived and released by the holder and owner
hereof by the acceptance of this bond and as provided in the Indenture.
This bond shall not become or be valid or obligatory for any purpose
until the authentication certificate hereon shall have been manually signed
by the Trustee.
[FORM OF TRUSTEE'S AUTHENTICATION CERTIFICATE FOR
BONDS OF THE 2002 SERIES]
This is the bond, of the series designated therein, described in the
within mentioned Indenture.
IBJ SCHRODER BANK & TRUST
COMPANY
As Trustee,
By: __________________________________
Authorized Officer
Section 2.03. Discharge of Company's Obligation for Payment. The
obligation of the Company to make any payment of interest on Bonds of the
2002 Series, when such interest shall be due and payable, shall be deemed to
be, and shall be, satisfied and discharged if the Company shall have paid all
interest under the Reimbursement Agreement then due and payable. The
obligation of the Company to make payments with respect to the principal of
Bonds of the 2002 Series at any time shall be deemed to be, and shall be,
satisfied and discharged if, at any time that any such payment of principal
shall be due, the Company shall have paid BNY Agent for all amounts then due
pursuant to Sections 2.03 and 2.04 of the Reimbursement Agreement. The
Trustee may conclusively presume that at any particular time, the obligations
of the Company to make payments with respect to the principal of and interest
on the Bonds of the 2002 Series shall have been satisfied and discharged up
until such time unless and until the Trustee shall have received a notice as
described in Section 12.01(k) of the Indenture. Whenever all of the
obligations of the Company to BNY Agent pursuant to the Reimbursement
Agreement shall have been satisfied and the Letter of Credit shall have been
terminated, the aggregate principal amount of all of the Bonds of the 2002
Series shall be surrendered by BNY Agent to the Trustee for cancellation, and
upon such surrender shall be deemed fully paid.
Section 2.04. Redemption Provisions for the Bonds of the 2002 Series.
The Bonds of the 2002 Series shall be subject to redemption as a whole or
in part, at any time, at the option of the Company prior to maturity upon
payment of the principal amount thereof.
In the event that the Revenue Bonds outstanding under the Indenture of
Trust, dated as of June 1, 1996, between the Maine Public Utility Financing
Bank and Fleet National Bank (the "Revenue Bond Indenture") shall become
immediately due and payable pursuant to Section 9.01(e) or 9.01(f) of the
Revenue Bond Indenture, all Bonds of the 2002 Series then outstanding shall
be redeemed by the Company, on the date such Revenue Bonds shall have become
immediately due and payable, at the principal amount of the Bonds of the 2002
Series.
The Trustee may conclusively presume that no redemption of Bonds of the
2002 Series is required pursuant to this Section 2.04 unless and until the
Trustee shall have received a written notice from BNY Agent stating that:
(a) BNY Issuing Bank has paid a drawing under the Letter of Credit made by
the trustee under the Revenue Bond Indenture to pay interest on or principal
of the Revenue Bonds and that the Company has not reimbursed BNY Agent for
such drawing; or (b) an "Event of Default" under the Reimbursement Agreement
has occurred and is continuing. Said notice shall also contain a waiver of
notice of such redemption by BNY Agent as holder of all of the Bonds of the
2002 Series then outstanding.
Any redemption pursuant to this Section 2.04 shall be made, together in
any case with interest accrued thereon to the redemption date, upon not less
than 30 days' nor more than 90 days' notice given by first class mail,
postage prepaid, to the holder of record at the date of such notice of each
Bond of the 2002 Series at his address as shown on the Bond register for
Bonds of the 2002 Series. Such notice shall be sufficiently given if
deposited in the United States mail within such period. Neither the failure
to mail such notice, nor any defect in any notice so mailed to any such
holder, shall affect the sufficiency of such notice with respect to other
holders. No notice of redemption need be given if the holders of all Bonds
of the 2002 Series called for redemption waive notice thereof in writing and
such waiver is filed with the Trustee.
Section 2.05 Duration of Effectiveness of Article Two. This Article
shall be of force and effect only so long as any Bonds of the 2002 Series are
outstanding.
ARTICLE THREE
Modification of the Indenture
Section 3.01. Clause (k) of Section 12.01 of the Indenture is hereby
amended and restated in its entirety to read as follows:
"(k) so long as any of the Bonds of the 2002 Series are
outstanding, upon receipt by the Trustees of a notice from the
holder of the Bonds of the 2002 Series that an event of default has
occurred under the Reimbursement Agreement and is continuing;"
Section 3.02. Duration of Effectiveness of Article Three. This Article
shall be of force and effect only so long as any Bonds of the 2002 Series are
outstanding.
ARTICLE FOUR
Authentication and Delivery of Bonds of the 2002 Series
Section 4.01. Upon the execution and delivery of this Third
Supplemental Indenture, Bonds of the 2002 Series in the aggregate amount of
Fifteen Million Eight Hundred Seventy-Five Thousand Dollars ($15,875,000) may
forthwith, or from time to time thereafter, and upon compliance by the
Company with the provisions of Article Five of the Indenture, be executed by
the Company and delivered to the Trustee and shall thereupon be authenticated
and delivered by the Trustee to or upon the written order of the Company.
ARTICLE FIVE
Section 5.01. The Company may enter into an agreement with the holder
of any registered Bond without coupons of any series providing for the
payment to such holder of the principal of and the premium, if any, and
interest on such Bond or any part thereof at a place other than the offices
or agencies therein specified, and for the making of notation, if any, as to
the principal payments on such Bond by such holder or by an agent of the
Company or of the Trustee. The Trustee is authorized to approve any such
agreement, and shall not be liable for any act or omission to act on the part
of the Company, any such holder or any agent of the Company in connection
with any such agreement.
Section 5.02. This Third Supplemental Indenture is executed and shall
be construed as an indenture supplemental to the Original Indenture, as
amended and supplemented, and shall form a part thereof, and, except as
hereby supplemented, the Original Indenture, as amended and supplemented, is
hereby ratified, approved and confirmed.
Section 5.03. The recitals contained in this Third Supplemental
Indenture are made by the Company and not by the Trustee and all of the
provisions contained in the Original Indenture, as amended and supplemented,
in respect of the rights, privileges, immunities, powers and duties of the
Trustee shall, except as hereinabove modified, be applicable in respect
hereof as fully and with like effect as if set forth herein in full.
Section 5.04. Nothing in this Third Supplemental Indenture contained
shall be deemed to abrogate, modify or contravene any provisions of the
Original Indenture, as amended and supplemented, required to be included
therein by any of the provisions of Section 310 to 318, inclusive, of the
Trust Indenture Act of 1939, it being the intention hereof that said
provisions of the Original Indenture, as amended and supplemented, shall
continue in full force and effect. Unless otherwise indicated, the terms
used in this Third Supplemental Indenture are intended to have the meanings
given to such terms in the Original Indenture, as amended and supplemented.
Section 5.05. Nothing in this Third Supplemental Indenture expressed
or implied is intended or shall be construed to give to any person other than
the Company, the Trustee, and the holders of the Bonds issued and to be
issued under the Indenture, any legal or equitable right, remedy or claim
under or in respect of the Original Indenture, as amended and supplemented,
or this Third Supplemental Indenture, or under any covenant, condition or
provisions therein or herein or in the Bonds contained; and all such
covenants, conditions and provisions are and shall be held to be for the sole
and exclusive benefit of the Company, the Trustee and the holders of the
Bonds issued and to be issued under the Indenture.
Section 5.06. The titles of Articles and any wording on the cover of
this Third Supplemental Indenture are inserted for convenience only.
Section 5.07. All the covenants, stipulations, promises and agreements
in this Third Supplemental Indenture contained made by or on behalf of the
Company or of the Trustee shall inure to and bind their respective successors
and assigns.
Section 5.08. Although this Third Supplemental Indenture is dated for
convenience and for the purpose of reference as of June 1, 1996, the actual
date or dates of execution by the Company and by the Trustee are as indicated
by their respective acknowledgments hereto annexed.
Section 5.09. In order to facilitate the recording or filing of this
Third Supplemental Indenture, the same may be simultaneously executed in
several counterparts, each of which shall be deemed to be an original, and
such counterparts shall together constitute but one and the same instrument.
IN WITNESS WHEREOF, MAINE PUBLIC SERVICE COMPANY has caused this Third
Supplemental Indenture to be signed in its corporate name and behalf by its
President or one of its Vice Presidents and its corporate seal to be hereunto
affixed and attested by its Secretary, or one of its Assistant Secretaries;
and IBJ SCHRODER BANK & TRUST COMPANY in token of its acceptance of the trust
hereby created has caused this Third Supplemental Indenture to be signed in
its corporate name and behalf by its President or one of its Vice Presidents
or one of its Second Vice Presidents and its corporate seal to be hereunto
affixed and attested by its Assistant Secretary or one of its Trust Officers,
all as of the day and year first above written.
MAINE PUBLIC SERVICE COMPANY
/s/ Larry LaPlante
Name: Larry LaPlante
Title: Vice President
CORPORATE SEAL
Attest:
/s/ Stephen A. Johnson
Name: Stephen A. Johnson
Title: Secretary
Signed, sealed and delivered
by MAINE PUBLIC SERVICE COMPANY
in the presence of:
/s/ Marilyn L. Bouchard
Marilyn L. Bouchard
/s/ Stephen J. Gallant
Stephen J. Gallant
IBJ SCHRODER BANK & TRUST COMPANY
/s/ Max Volmar
Name:Max Volmar
Title:Vice President
CORPORATE SEAL
Attest:
/s/ Kerry A. Monaghan
Name: Kerry A. Monaghan
Title: Assistant Secretary
Signed, sealed and delivered
by IBJ SCHRODER BANK & TRUST
COMPANY in the presence of:
/s/ Barbara McCluskey
Barbara McCluskey
/s/ Susan Lavelle
Susan Lavelle
STATE OF MAINE )
: ss.:
COUNTY OF AROOSTOOK )
June 11, 1996
Then personally appeared the above-named Larry LaPlante Vice President
of Maine Public Service Company and acknowledged the foregoing instrument to
be his free act and deed in his said capacity and the free act and deed of
said corporation.
Before me,
/s/ Alice E. Shepard
Notary Public
Alice E. Shepard
Notary Public, Maine
My Commission Expires October 29, 2000
NOTARIAL SEAL
STATE OF NEW YORK )
: ss.:
COUNTY OF RICHMOND )
June 14, 1996
Then personally appeared the above-named Max Volmar, a Vice President
of IBJ Schroder Bank & Trust Company and acknowledged the foregoing
instrument to be his free act and deed in his said capacity and the free act
and deed of said corporation.
Before me,
/s/ Norma Pacifico
Notary Public
My Commission expires: August 31, 1996
Norma Pacifico
Notary Public, State of New York
No. 43-5001265
Qualified in Richmond County
Certificate filed in Manhattan County
Commission Expires August 31st, 1996
NOTARIAL SEAL
Exhibit 10(u)
AMENDMENT NO. 3
to the
REVOLVING CREDIT AGREEMENT
AMENDMENT NO. 3, dated as of October 8, 1995, 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, and Amendment No.
2, dated as of May 11, 1992 (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 set
forth herein. Accordingly, the parties hereto agree that, on the conditions
and subject to the limitations contained herein, the Agreement be and the
same hereby is amended as follows:
1. Paragraph 2.9 is amended by deleting said paragraph
in its entirety and substituting therefor the following:
2.9 Commitment Fee. The Company agrees to pay to the Banks a
fee (the "Commitment Fee") equal to 3/8 of 1% per annum (computed on the
basis of a 360 day year for the actual number of days involved) on the
average daily unused amount of the Aggregate Commitments (provided, however,
that Credit B Loans will not be construed as usage in calculating the
Commitment fee) for the period from and including October 8, 1995 until the
expiration or termination of the Aggregate Commitments. The Commitment Fee
shall be payable quarterly in arrears and prorated on the last day of each
March, June, September and December, commencing on the first such day
following the Effective Date. Payment of the Commitment Fee shall be made
to the Agent and, upon receipt thereof, the Agent shall promptly remit to
each Bank its pro rata share thereof according to the Aggregate Commitments.
2. Paragraph 11 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, as Agent
One Wall Street
New York, New York 10286
Attention: John W. Hall, Vice President
Shawmut Bank of Boston
One Federal Street
Boston, Massachusetts 02211
Attention: John Rafferty, Director
Fleet Bank of Maine
80 Exchange Street
P.O. Box 923
Bangor, Maine 04402-0923
Attention: Neil C. Buitenhuys, Vice President
3. Except as amended hereby, the Agreement shall remain
in full force and effect.
4. 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.
5. 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.
6. 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: /s/ L. E. LaPlante
Title: Vice President, Finance
and Treasurer
THE BANK OF NEW YORK, as Agent
By: /s/ John W. Hall
Title: Vice President
Execution of the foregoing
Amendment No. 3 by the Agent
is hereby consented to:
THE BANK OF NEW YORK
By: /s/ John W. Hall
Title: Vice President
SHAWMUT BANK, N.A.
By: /s/ J. P. Rafferty
Title: Director
FLEET BANK OF MAINE
By: /s/ Neil C. Buitenhuys
Title: Vice President
Exhibit 13
(Front Outside Cover)
Maine Public Service Company
1996 Annual Report
We put a lot of energy into Northern Maine
(Front Inside Cover)
Maine Public Service Company
(Graphic - Map of Territory Served)
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, nuclear, and
oil-fueled facilities, as well as an independent wood-burning cogenerator.
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 Front Inside Cover
President's Letter 1-2
Analysis of Financial Condition
and Review of Operations - 1996 3-11
Shareholder Information 11
Five-Year Summary of Selected Financial Data 12
Independent Auditors' Report 13
Financial Statements and Notes 14-27
Consolidated Financial Statistics 28-29
Consolidated Operating Statistics 30-31
Directors 32
Executive Officers and Stock Back Cover
Transfer Information
(Photo)
Irwin F. Porter, age 78, died September 4, 1996, after a long
illness. His 44-year career was dedicated to banking in Presque Isle,
Maine. He served over twenty-one years, from 1973 to 1994, on Maine
Public Service Company's Board of Directors. 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@agate.net
(Page 1)
President's Letter
to our Shareholders and
Employees
The year 1996 was disappointing for your Company with earnings per
share of $1.31, compared to a net loss of $3.29 per share in 1995. As you
may recall, the Company had non-cash write-offs of $8.3 million in 1995,
as part of the four-year rate stabilization plan agreement with the Maine
Public Utilities Commission (MPUC). Absent these write-offs, the 1995
earnings would have been $1.87 per share. The lower performance in 1996
can be attributed to the loss of Houlton Water Company as a customer,
along with the erratic performance of the Maine Yankee Nuclear Plant.
Retail energy sales were the same as last year with our service territory
continuing to feel the economic impact of the 1994 closure of Loring Air
Force Base, as well as a very mild December. Although the first year of
our rate stabilization plan increased rates 4.4% in 1996, the elimination
of the fuel adjustment clause caused the Company to absorb replacement
power costs for the three months of unscheduled outages at Maine Yankee,
along with the scheduled annual 5% increase in our Wheelabrator-Sherman
contract (currently 12.7 cents/KWH).
Maine Yankee had been operating at 90 percent of capacity since early
1996 pending resolution of issues relating to an investigation initiated
by the Nuclear Regulatory Commission. Since December 6, Maine Yankee has
been out of service and, as of this writing, it is unlikely that it will
return to service until mid-summer or perhaps later. Replacement power
costs, along with increased capacity costs, have financially challenged
the Company. The Maine Yankee situation and the burdensome
Wheelabrator-Sherman contract have, and will continue to have, a negative
impact on earnings and cash flows. We therefore have reduced our annual
dividend from $1.84 to $1.00, effective April 1, 1997, in order to
conserve cash. In addition, the continued shutdown of Maine Yankee is
likely to place us in default of coverage tests under our debt instruments
with our banks. We are negotiating with our banks to restructure our debt
agreements; have requested a contract restructuring with
Wheelabrator-Sherman; and may be filing for rate relief with the MPUC. It
should be noted that we have been unsuccessful in contract restructuring
efforts with Wheelabrator-Sherman over the last three years.
The MPUC issued its report and recommended plan for Electric Utility
Industry Restructuring on December 31, 1996. Under the MPUC
recommendations, retail competition would begin January 1, 2000 and
generation would not be subject to economic regulation by the MPUC. Under
the proposal, your Company will not be required to sell its generating
assets; however, if it decides to retain its generating assets, it must
create a separate generating subsidiary. Our transmission and
distribution businesses will continue to be regulated, transmission by the
Federal Energy Regulatory Commission (FERC) and distribution by the MPUC.
Stranded investment is a major element of restructuring. Stranded
investment affects your Company with regard to its power contract with
Wheelabrator, the excess of the contract price over market price, and the
collection of the Seabrook regulatory asset currently scheduled to be
amortized and collected through 2016. Other stranded investment issues
are associated with the values placed on generating assets such as Wyman,
Maine Yankee, and our Tinker Hydro facility located in Canada. These
generating
(Page 2)
facilities could be subject to stranded investment if their market value
is different than their book value. We will certainly contest anything
other than full recovery of stranded investment for your Company.
The MPUC restructuring proposal is awaiting action by the State
Legislature whereby they can approve, modify, or reject the proposal. It
is difficult to predict the outcome of this proposal.
On a more positive note, your Company has been aggressive in the
promotion of economic development. We hired a Director of Economic
Development in October, 1996 and have committed a budget to promote
economic development in our service area. Recently, a hardwood flooring
firm located at the Loring Commerce Centre (formerly Loring Air Force
Base) and, although not a large employer, it is the first major private
sector entity to make a long-term commitment to the former Air Base. We
are hopeful that this will be the start of further economic activity at
Loring.
We also are pleased to announce that five of our largest industrial
customers are under contract through the year 2000. Although we had to
offer discounts to secure these contracts, we have eliminated the risk of
losing these major customers as we prepare for customer choice and
competition.
As we go forward, the Company continues to position itself for
competition. A very critical asset has been Maine Yankee, which has
supplied approximately 40% of our requirements over the years at a very
low cost. A permanent loss of Maine Yankee would create a serious
financial hardship for your Company and may require rate increases that
could affect our ability to compete. Another critical issue in
preparation for competition is whether your Company will continue to be in
the generation business or will only market power and not produce it.
We continue to look at investments in non-regulated services to
determine which are best suited for your Company.
In 1996, we reorganized our corporate structure into three sections:
a wholesale sector, retail sector, and administration. We continue to
look at our organization and believe that the recent changes have us well
positioned as we move forward, especially in the transmission and
distribution functions, as well as power supply.
I would like to thank you, our shareholders, for the confidence you
have placed in us to lead the Company during this transition period to
deregulation. Although we are faced with uncertainty as we progress, you
have my commitment that we will be responsive to you, our shareholders,
our customers, and our employees. I would like to thank our dedicated
workforce for their efforts over the year as we continue to accomplish
more with fewer employees.
Sincerely,
/s/ Paul R. Cariani
Paul R. Cariani
President and CEO
(Page 3)
Analysis of Financial Condition and Review of Operations - 1996
RESULTS OF OPERATIONS
Operating Revenues and Energy Sales
Consolidated operating revenues and MWH sales for the years 1996,
1995, and 1994 are as follows:
Consolidated Operating Revenues and Megawatt Hours Sold
(Dollars in Thousands)
1996 1995 1994
Dollars MWH Dollars MWH Dollars MWH
Residential
$19,961 169,298 $19,081 168,640 $19,647 175,685
Commercial & Industrial - Large
10,112 134,588 9,437 128,478 9,225 127,327
Commercial & Industrial - Small
16,420 163,804 15,723 165,914 15,614 167,485
Other Retail
1,523 13,166 1,701 14,859 2,895 31,736
Total Retail
48,016 480,856 45,942 477,891 47,381 502,233
Sales for Resale
2,096 55,958 6,955 123,793 6,946 119,450
Total Primary
50,112 536,814 52,897 601,684 54,327 621,683
Secondary Sales
4,797 229,141 619 22,115 1,535 88,241
Total Sales of Electricity
54,909 765,955 53,516 623,799 55,862 709,924
Other 2,355 1,763 2,506
Total Operating Revenue
$57,264 $55,279 $58,368
Primary sales for 1996 were 536,814 MWH, approximately 10.8% lower
than sales of 601,684 MWH in 1995 and 13.7% lower than sales of 621,683
MWH in 1994. 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 principal reason for the primary sales
decrease. In 1995, HWC, the Company's largest customer, represented 11.1%
of consolidated MWH sales and 8.4% of consolidated operating revenues.
Sales for resale were higher in 1995 than 1994 because of increased sales
to HWC. Retail sales were 480,856 MWH in 1996, an increase of 2,965 MWH,
(0.6%) over 1995 sales reflecting increased sales to two large industrial
customers: J. Paul Levesque & Sons and McCain Foods. Compared to 1994,
retail sales decreased 21,377 MWH, (4.3%) in 1996 because of the closure
of Loring Air Force Base, which also impacted residential and small
commercial and industrial sales.
During 1996, the Company entered long-term power contracts with two
of its largest customers. The price under these contracts are lower than
permitted under the Company's standard rates, but obligates them to
purchase all of their electrical requirements through the year 2000. One
additional customer has signed a similar agreement that must be approved
by the Maine Public Utilities Commission (MPUC), while two others have
verbally accepted the Company's offers.
Secondary sales for 1996 of $4,797,000 were $4,178,000 and $3,262,000
more than 1995 and 1994, respectively. 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
Company's Maine Yankee entitlement was sold in 1996 and 1994, during
periods of surplus capacity, but not in 1995, due to the year-long
resleeving shutdown as further discussed in the "Maine Yankee" section of
this Annual Report.
The MPUC has jurisdiction over retail rates. As discussed in the
"Regulatory Proceedings - Four-Year Rate Plan Approved" section of this
Annual Report, the MPUC approved a four-year rate plan effective January
1, 1996. The plan allows for annual increases in retail rates and
eliminates the fuel clause. Prior to the four-year rate plan, the Company
had not sought a base rate increase since November 1, 1992.
(Page 4)
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 126.5% of normal production levels in 1996 and provided 21.1% of the
Company's energy requirements. In 1995, hydro production was 90.8% of
normal and provided 18.3% of the Company's energy needs. Hydro production
in 1994 was 88.9% of normal and accounted for 15.8% of the Company's
energy requirements. The availability of low cost hydro, at $17.33 per
megawatt hour in 1996, reduces the need for more expensive sources of
energy. As more fully explained in the "Maine Yankee" section of this
Annual Report, Maine Yankee returned to service in January of 1996
following a year-long outage. During 1996, Maine Yankee was restricted to
90% of rated capacity and was out of service a total of 13 weeks but was
able to provide 31.1% of the Company's energy requirements compared to
only 1.5% in 1995 and 43.3% in 1994. Maine Yankee operated at full
capacity in 1994 with the exception of an unscheduled four-week outage
beginning in mid-July.
(Chart)
Electric Output By Sources
(Percent)
1992 1993 1994 1995 1996
Oil 4.5 3.6 2.4 3.6 1.2
Cogeneration 18.2 16.7 16.8 19.1 16.1
Purchases 23.0 21.8 21.7 57.5 30.5
Nuclear 36.3 37.9 43.3 1.5 31.1
Hydro 18.0 20.0 15.8 18.3 21.1
On December 6, 1996, Maine Yankee was again taken out of service to
address concerns regarding cabling issues. The nuclear plant is not
expected to return to service until the Summer of 1997. The Company has
been incurring replacement power costs of approximately $170,000 per week
while the Plant has been out of service. The Company purchases economical
replacement energy from various sources, including NB Power, Bangor
Hydro-Electric, and Central Maine Power on a competitive basis. These
purchases accounted for 30.5% of the Company's energy supply in 1996,
compared to 57.5% and 21.7% in 1995 and 1994, respectively. The larger
than normal energy purchases in 1995 reflect the loss of Maine Yankee
production. The Company's oil-fired generating facilities provided 1.2%
of the Company's requirements in 1996, compared to 3.6% in 1995 and 2.4%
in 1994. In 1986, under an agreement ordered by the Maine Public
Utilities Commission that may be renewed by either party in 2000, the
Company began purchasing the output from an 18-megawatt wood-burning
independent power producer, currently owned by Wheelabrator-Sherman. The
mandated purchases from this facility represented 16.1% of the Company's
energy needs in 1996, compared to 19.1% and 16.8% in 1995 and 1994,
respectively.
Operating Expenses
For the three-year period 1994-1996, purchased power expenses are as
follows:
(Dollars in Thousands)
1996 1995 1994
Wheelabrator-Sherman $15,593 $14,507 $13,932
Maine Yankee 10,185 7,972 9,645
NB Power 3,498 9,091 3,841
System Purchases 2,544 408 346
Total $31,820 $31,978 $27,764
The increases in Wheelabrator-Sherman expenses reflect an annual 5%
contractual price increase and increased generation in 1996 due to
favorable operating conditions. For 1996, 1995, and 1994, these mandated
purchases from Wheelabrator-Sherman represented 49.0%; 45.4%; and 50.2%;
respectively, of total purchased power expenses. As more fully explained
in the "Maine Yankee" section of this Annual Report, Maine Yankee was down
for 1995 to resleeve the steam generator tubes and for a scheduled
refueling and maintenance outage. During 1996, Maine Yankee was off-line
for a total of approximately thirteen weeks to address several issues.
The facility has not operated since December 6, 1996 and is not expected
to return to service until the summer of 1997 at the earliest. Maine
Yankee had a one-month unscheduled outage for repairs in 1994. For
ratemaking, the Company normalizes refueling and maintenance expenses due
to scheduled refuelings over the refueling cycle. Unscheduled outages are
charged to expense as incurred. As part of its rate plan approved by the
Maine Public Utilities Commission, the Company's $1.3 million share of the
1995 steam generator tube resleeving was deferred in 1995 and will be
collected in rates and expensed over five years beginning in 1996. For
1995, after considering the deferral of the resleeving expenses, Maine
Yankee's fuel and capacity expenses were well below normal, as resources
were used to complete the resleeving project. For 1996, the resleeving
amortization, as well as additional expenses to address issues found
during the previously mentioned outages, were the principal reasons for
the increase in expenses. The Company purchased Maine Yankee replacement
power principally from NB Power. While 1996 and 1994 purchases were
similar, purchases in 1995 were $5,593,000 higher because of the extended
Maine Yankee outage. System purchases in 1996 increased by $2,136,000
compared to 1995 due to increased power marketing activities, as discussed
in the "Operating Revenues and Energy Sales" section of this Annual
Report.
(Page 5)
Other operation and maintenance expenses for the three-year period
are as follows:
(Dollars in Thousands)
1996 1995 1994
Generation
Fuel Expense $ 387 $ 824 $ 602
Other 1,571 2,031 2,096
1,958 2,855 2,698
Deferred Fuel (1,375) (4,937) (744)
Fuel Expense Write-off - 3,500 -
Transmission and
Distribution 4,228 3,668 4,103
Customer Accounting and
General Administrative 7,629 6,740 6,669
Total $12,440 $11,826 $12,726
Fuel expenses for generation decreased by $437,000 in 1996, as
compared to 1995, because of Maine Yankee's availability in 1996 which
displaced oil-fired generation. Other generation expenses decreased by
$460,000, reflecting the lay-up of the Caribou Steam Plant as of January
1996 due to the loss of two customers, Loring Air Force Base and Houlton
Water Company. The Plant is projected to remain inactive for a minimum of
five years. As more fully discussed in the "Regulatory Proceedings --
Four-Year Rate Plan Approved" section of this Annual Report, the fuel
clause adjustment was eliminated with the four-year rate plan effective on
January 1, 1996 with the exception of the annual Wheelabrator-Sherman
deferral of fuel expenses. Deferred fuel expense, a component of other
operation and maintenance expenses, was a negative $1,375,000 in 1996,
compared to a negative $4,937,000 in 1995 and a negative $744,000 in 1994.
Negative deferred fuel indicates that current fuel costs have exceeded
fuel revenues and have been deferred to a period when these costs will be
collected. As part of the 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 in 1995 under the previous
fuel clause. For 1996, transmission and distribution expenses were
$560,000 more than 1995 reflecting increased wheeling costs related to
increased power marketing activities and additional tree trimming.
Customer accounting and general and administrative expenses increased by
$889,000 in 1996 reflecting $402,000 in expenses related to an early
retirement program in March 1996 and rate plan treatment of postretirement
medical expenses of $106,000.
Maine Yankee
The Company owns 5% of the Common Stock of Maine Yankee, which
operates an 860 MW nuclear power plant (the Plant) in Wiscasset, Maine.
In 1996, Maine Yankee provided approximately 31.1% of the Company's energy
requirements. In early February of 1995, during a scheduled
refueling-and-maintenance shutdown, Maine Yankee detected an increased
rate of degradation of the Plant's 17,000 steam generator tubes in excess
of the number expected and started evaluating several courses of action.
Maine Yankee could not resume operations until the necessary repairs had
been made.
Maine Yankee repaired the tubes by inserting and welding short
reinforcing sleeves of an improved material in almost all of the steam
generator tubes. The sleeving of the steam generator tubes was not
completed until mid-December of 1995, at a cost of approximately $27
million, with the Company's share being approximately $1.3 million.
During 1995, while Maine Yankee was out of service, the Company incurred
additional replacement power costs of approximately $5.7 million. As more
fully explained in the "Regulatory Proceeding - Four-Year Rate Plan
Approved" section of this Annual Report, in late 1995 the Maine Public
Utilities Commission approved a multi-year rate plan for the Company. As
an element of the rate plan, the Company eliminated the fuel adjustment
clause except for the cost of power purchased from the
Wheelabrator-Sherman Energy Company, an independent power producer. As
part of the rate plan, $2.1 million, net of income taxes, of the
replacement power costs associated with the Maine Yankee outage was
written off in 1995, $300,000, net of income taxes, will be collected in
rates and amortized over the four-year rate plan period, and an estimated
$1.3 million, net of income taxes, will be deferred until 2000, when rate
recovery will be provided. The rate plan also includes a mechanism to
handle similar unexpected Maine Yankee outages during the rate plan
period. In addition, the rate plan allows for the five-year amortization
of the actual sleeving expenses.
On December 4, 1995, when the sleeving project was substantially
complete, Maine Yankee obtained a copy of a letter from an organization
with a history of opposing nuclear power development to a State of Maine
nuclear safety official based on documentation from an anonymous employee
or former employee of Yankee Atomic Electric Company (Yankee Atomic), an
affiliate of Maine Yankee that has regularly performed nuclear engineering
and related services for Maine Yankee and other nuclear plant operators.
The letter contained allegations that Yankee Atomic knowingly performed
inadequate analyses to support two license amendments to increase the
rated thermal power at which the Maine Yankee Plant could operate. It was
further alleged in the letter that Maine Yankee deliberately
misrepresented the analyses to the Nuclear Regulatory Commission (NRC) in
seeking the license amendments. The allegedly inadequate analyses related
to the operation of the Plant's emergency core cooling system (ECCS) and
the calculation of the Plant containment's peak postulated accident
pressure, both under certain assumed accident conditions. The analyses
were used in support of license amendments that authorized Plant power
uprates from 2,440 megawatts thermal, a level equal to approximately 90
percent of the maximum electrical capability of the Plant, to its current
100-percent rated level.
The NRC's Office of the Inspector General (OIG) and its Office of
Investigation (OI) initiated separate investigations of the allegations
made in the letter. On May 9, 1996, the OIG, which was responsible for
investigating only the actions of the NRC staff and not those of Maine
Yankee and Yankee Atomic, reported on its investigation, finding
deficiencies in the NRC staff's review, documentation, and communications
practices in connection with the license amendments, as well as
"significant indications of possible licensee violations of NRC
requirements and regulations." Any such violations by Maine Yankee would
be within the purview of the OI investigation, which, with related issues,
is being reviewed by the United States Department of Justice. A separate
internal investigation authorized by the boards of directors of Maine
Yankee and Yankee Atomic and conducted by an independent law firm noted
several areas for improvement, including regulatory communications,
definition of responsibilities between Maine Yankee and Yankee Atomic, and
tracking and documentation of regulatory compliance, but found no
wrongdoing by Maine Yankee or Yankee Atomic or any of their employees.
The Company cannot predict the results of the investigations by the OI and
Department of Justice.
(Page 6)
On January 3, 1996, the NRC issued a "Confirmatory Order Suspending
Authority For And Limiting Power Operation And Containment Pressure
(Effective Immediately) and Demand For Information" (the Order), after
reviewing the safety analyses performed by Yankee Atomic relating to Maine
Yankee's license amendment applications for the power uprates. The Order
limited the power output of Maine Yankee to approximately 90% of its rated
maximum until the NRC reviewed and approved plant-specific analyses
meeting the NRC's criteria for operation of the ECCS under certain
postulated accident conditions, in lieu of the analyses based on the
questioned computer code. The Order also required an integrated
containment analysis demonstrating that the maximum calculated containment
pressure under certain postulated accident conditions does not exceed the
design pressure of the Plant's containment. On January 10, 1996, Maine
Yankee filed with the NRC information specified in the Order that it
believes supports operation of the Plant at up to 90% of the Plant's
capability. Maine Yankee attained the 90% level of the Plant's capability
on January 24, 1996.
On June 7, 1996, the NRC formally notified Maine Yankee that it
planned to conduct an "Independent Safety Assessment" (ISA) of the Maine
Yankee Plant in conjunction with the State of Maine to provide an
independent evaluation of the safety performance of Maine Yankee and as a
"follow-up" to the NRC's OIG report. The NRC stated that the overall
goals and objectives of the ISA were: "(a) provide an independent
assessment of conformance to the design and licensing basis; (b) provide
an independent assessment of operational safety performance; (c) evaluate
the effectiveness of license self-assessments, corrective actions and
improvement plans; and (d) determine root cause(s) of safety significant
findings and conclusions." The NRC further informed Maine Yankee that the
ISA would be carried out by a team of NRC personnel and contractors who
were "independent of any recent or significant involvement with the
licensing, regulation, or inspection of Maine Yankee."
On July 20, 1996, Maine Yankee went off-line to add pressure relief
valves to the primary component cooling system, as determined during a
comprehensive internal review by Maine Yankee of plant systems and
equipment. On September 2, 1996, the Plant returned to service, attaining
the 90% capacity limit.
On October 7, 1996, the NRC released the results of the ISA at Maine
Yankee that concluded that although Maine Yankee was in general
conformance with its licensing basis, several items of deficient or weak
performance existed. The ISA report further concluded that the overall
performance at Maine Yankee was "adequate" for operation of the Plant.
The ISA report further concluded that the two principal causes for
these deficiencies were: (1) that economic pressures to be a low-cost
power producer had limited resources to address corrective actions and
some improvements; and (2) that a questioning culture was lacking, which
had resulted in a failure to identify or properly correct significant
problems in areas perceived by Maine Yankee to be of low safety
significance. In a letter to Maine Yankee accompanying the ISA report,
Chairman of the NRC Shirley Ann Jackson noted that although overall
performance at Maine Yankee was considered adequate for operation, a
number of significant weaknesses and deficiencies identified in the report
would result in NRC violations. The letter also directed Maine Yankee to
provide to the NRC its plans for addressing the root causes of the
deficiencies noted in the ISA and identified the NRC offices that would be
responsible for overseeing corrective actions and taking any appropriate
enforcement actions against Maine Yankee, including
as-yet-determined monetary penalties.
The Plant went off-line again on December 6, 1996 to review and
resolve several cable separation and cable routing issues. Maine Yankee
will complete a root cause analysis of the cable issues and will present
the analysis to the NRC regional office prior to startup. Having detected
indications of minor leakage in a small number of the Plant's fuel rods,
Maine Yankee has used this out-of-service time to inspect the Plant's 217
fuel assemblies and has determined that 68 of the fuel assemblies should
be replaced. In addition, 24 fuel assemblies will be replaced as part of
a refueling.
On December 10, 1996, Maine Yankee filed its formal response to the
ISA report. In this report, Maine Yankee promised to substantially
increase expenditures to address the source of the deficiencies noted in
the ISA report, and that the improvements would include physical and
operating changes to the Plant, as well as increased staffing primarily in
the engineering and maintenance areas, and other changes.
Consequently, Maine Yankee's 1997 Operating Budget has been increased
by approximately $46.3 million for additional employees, training and
equipment in order to address the root causes of the deficiencies
identified in the ISA. The Company's share of this additional amount is
approximately $2.3 million.
Maine Yankee announced the resignation of President Charles D.
Frizzle on December 20, 1996. The Board of Directors of Maine Yankee
unanimously decided that new leadership was required to deal with
deep-rooted cultural issues, a changing regulatory environment, and
unprecedented financial pressures. On February 13, 1997, Maine Yankee and
Entergy Nuclear, Inc. (Entergy), which is a subsidiary of Entergy
Corporation, a Louisiana-based utility holding company and leading nuclear
plant operator, entered into a contract under which Entergy will provide
management services to Maine Yankee. At the same time, Michael Sellman of
Entergy assumed the office of President of Maine Yankee, and the contract
contemplates that Entergy will provide other management personnel to Maine
Yankee.
On January 29, 1997, the NRC announced it had placed the Plant on its
"watch list", in "Category 2", which includes plants that display
"weaknesses that warrant increased NRC attention," but do not warrant a
shut-down order. The Plant is one of 14 nuclear units in the United
States on the January 29 "watch list" and one of six listed there for the
first time.
The Company expects the Plant to remain off-line until the fuel
assembly replacement and thorough inspections of the Plant's electrical
cabling and steam generators are completed, and restarting is approved by
the NRC. The Company cannot predict how long the Plant will remain
off-line, and will make replacement power plans for an outage that could
last through the summer of 1997.
The Company has been incurring replacement power costs of
approximately $170,000 per week while the Plant has been out of service.
In addition, the Company is responsible for the previously mentioned
additional operating costs of $2.3 million associated with the ISA
inspection. Further costs are expected when Entergy Corporation begins
providing management services to Maine Yankee. Additional costs may also
be expected if the complexity of the cable separation and associated
issues require an extended period for their resolution. These additional
costs can be expected to adversely impact the Company's 1997 financial
results.
(Page 7)
Under the Company's multi-year rate plan, as described in the
"Regulatory Proceedings - Four-Year Rate Plan Approved" section of this
Annual Report, the Company has the right to receive specified retail rate
increases through 1999. This plan also includes provisions for additional
cost recovery in certain extraordinary situations such as very low
earnings or in the event of a Maine Yankee Plant outage exceeding six
consecutive months. The Company will continue to assess whatever options
it may have to recover any additional costs and, in addition, is making
every effort to reduce its 1997 cash expenditures. These efforts will
include a review of the level of dividends on the Company's Common Stock.
Moreover, the Company's short-term revolving credit agreement, as
well as a letter of credit supporting its 1996 Series of tax-exempt bonds,
contain interest coverage tests that the Company must satisfy to avoid
default. The Company now believes, based on the projected additional
Maine Yankee expenses and replacement power costs during the Plant outage,
that it will likely be in violation of these interest coverage tests for
the twelve months ended March 31, 1997. The Company will seek a waiver of
these requirements from the necessary parties. The Company anticipates
that the waiver will be granted, but cannot predict the terms of any such
waiver.
In a related matter, a Maine-based group that originally announced
its intention to start gathering signatures toward a new referendum to
force a permanent closure of the Plant by 2000, has now indicated its
intent to modify the referendum to prevent any renewal or extension of
Maine Yankee's operating license, currently due to expire in June 2008.
The group stated that it hoped to put the issues before the Maine
electorate in November, 1998. The Company cannot predict whether such a
referendum will be held or its outcome.
As an owner of Maine Yankee, the Company is responsible for its
proportional share of Maine Yankee operating expenses, including fuel and
decommissioning expenses. Furthermore, under a Capital Funds Agreement,
the Company, along with the other sponsoring utilities, has agreed to
provide Maine Yankee's capital requirements which cannot be obtained from
other sources. This obligation is limited to each owner's interest in
Maine Yankee, subject to obtaining necessary regulatory approvals.
In 1994, pursuant to FERC authorization, Maine Yankee increased its
annual collection for decommissioning to $14.9 million, approximately
$735,000 a year for the Company. This increase was based on a new
decommissioning estimate, assuming dismantlement and removal, of $317
million (in 1993 dollars), as a result of an external engineering study.
As of December 31, 1996, Maine Yankee's decommissioning funds are valued
at $163.5 million. The decommissioning of nuclear power plants is subject
to changes in legal and regulatory requirements as well as technological
changes.
Earnings and Dividends
For 1996 and 1994, earnings per share were $1.31 and $2.99,
respectively. The loss of Houlton Water Company as a customer in early
1996 and additional Maine Yankee capacity and replacement power expenses
from outages totalling thirteen weeks were the principal reasons for the
decrease in 1996 earnings. For 1995, earnings per share before and after
extraordinary items were $.57 and a loss of $3.29, respectively.
Write-offs of the Company's remaining wholesale investment in
Seabrook and other wholesale plant have been classified as extraordinary
items resulting in a loss of $6.2 million, net of income taxes, $3.86 per
share. In addition to the extraordinary write-offs in 1995, the Company
also charged $2.1 million to operating expenses, net of income taxes, or
$1.30 per share, for previously deferred retail fuel representing the
replacement power expenses incurred during the Maine Yankee resleeving
outage in 1995. As discussed in the "Regulatory Proceedings" section of
this Annual Report, these write-offs were an element of the four-year rate
plan approved by the Maine Public Utilities Commission on November 13,
1995.
The Company's return on equity for 1996 was 5.48% compared to a
negative 12.33%, after extraordinary items for 1995, and 10.33% for 1994.
Dividends paid per share for the years 1994 through 1996 were $1.84 per
share. For 1996 and 1994, the dividend payout ratios were 141% and 62%,
respectively. Before considering the rate plan write-offs, the 1995
payout ratio was 98.4%.
In consideration of the additional operating costs at Maine Yankee
and the uncertainty of its continued operations, your Board of Directors
at its March 7, 1997 meeting declared a dividend of $.25 per share, a
reduction of 46%. This action, along with other actions to control 1997
construction expenditures and operating expenses, is required to improve
the Company's cash flows. For additional information, see the "Maine
Yankee" and "Liquidity and Capital Resources" sections of this Annual
Report.
The table below portrays the cost components of an average kilowatt
hour sale for the three-year period, based on actual sales for those
years. The impact of the extraordinary and deferred fuel write-offs in
1995 totalling $8,340,000, net of tax, has not been considered to obtain
comparability with previous years. The fuel component for each of the
years reflects the fuel recoveries authorized via the annual fuel
adjustment clauses.
Components of Costs for
Average Revenue Per Primary Sale KWH
Before 1995 Write-offs
(Cents)
1996 1995 1994
Fuel 3.29 3.21 2.90
Purchased Power Capacity and
Other Operations 4.06 3.39 3.38
Depreciation .50 .43 .40
Seabrook Amortization .26 .28 .28
Taxes .67 .70 .86
Interest .66 .63 .62
Other Revenues (.50) (.35) (.48)
Return to Shareholders .39 .50 .78
Average Revenue Per
Primary Sale KWH 9.33 8.79 8.74
(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 1996, despite the loss of Houlton Water Company, previously our
largest customer, and additional Maine Yankee capacity and replacement
power expenses from thirteen weeks of unscheduled outages, the Company was
able to fund its construction requirements and pay the dividends without
requiring additional short-term borrowings. Net cash flows generated from
operating activities were $7.4 million in 1996. During 1996, a new $15
million series of 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, and during 1996, $1.1 million of
the bonds' proceeds were withdrawn based on qualifying property additions
and eligible issuance costs. At the end of 1996, the Company has
approximately $4.1 million available for future property additions over
the next two and one-half years. The Company 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. At the end of 1996, common shareholders' equity was 47.3%
of the Company's capital structure, higher than the industry average.
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.
In 1994, operating activities generated net cash flows of $10.3
million. In addition, the Company received the final payment of $1.1
million from the trustee of the 1991 Series of tax-exempt bonds upon the
completion of qualifying facilities. The Company paid dividends of $3
million, purchased 43,000 shares of its Common Stock in early 1994 for
$1.1 million, made debt payments of $1.9 million, including the final
payment on its 4-3/4% First Mortgage Bonds, and invested $4.4 million in
electric plant. During 1994, the Company had sufficient cash flows and
did not require short-term borrowings from its credit facilities.
For additional information regarding construction expenditures for
1994 to 1996 and anticipated construction expenditures for 1997, 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 1996 the Company periodically
required short-term borrowings from its credit facilities. As was the
case at the end of 1995, the Company ended 1996 with $1.4 million of notes
outstanding under the credit facilities. During 1994 to 1996, required
borrowings 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 provides $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 1996, the effective
interest rate since issuance for this series was 5.61%.
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.
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, the
Company does not anticipate using the program to adjust its capital
structure.
The Company can also issue First Mortgage Bonds of $17.5 million and
Second Mortgage Bonds of $24 million without bondable property additions.
For additional information on long-term debt, see Note 8, "Long-Term
Debt", of the Notes to Consolidated Financial Statements.
The Company's success with its rate plan depends on the normal
operation of Maine Yankee. Additional capacity and replacement power
expenses during unscheduled Maine Yankee outages adversely impact the
Company's earnings and cash flows. As more fully explained in the "Maine
Yankee" section of this Annual Report, the Company's rate plan includes
provisions for additional cost recoveries in the event of a Maine Yankee
Plant outage of more than six months or when earnings fall below certain
prescribed levels. For additional information on the rate plan, see the
"Regulatory Proceedings -- Four-
(Page 9)
Year Rate Plan Approved" section of this Annual Report. Although the
Company will continue to assess whatever options are available under the
rate plan, all 1997 cash expenditures, including the level of dividends on
the Company's Common Stock, will be reviewed. In addition, the Company's
short-term revolving credit agreement, as well as the letter of credit
supporting the 1996 Series of tax-exempt bonds, contain interest coverage
tests that the Company must satisfy to avoid default. Based on projected
capacity expenses for Maine Yankee in early 1997, as well as replacement
power expenses during 1997, the Company now believes that it will likely
be in violation of these interest coverage tests for the twelve months
ended March 31, 1997. The Company will seek waivers from these
requirements from the necessary parties, but cannot predict the terms of
any such waiver or whether the waivers will be granted.
Employees
At the end of 1996, the Parent Company had 155 full-time employees
compared to 169 for 1995. The lay-up of the Caribou Steam Plant and the
corresponding voluntary early retirement in late 1995 to create vacancies
for the displaced workers, along with an additional early retirement
program in early 1996, caused the decrease in the number of employees.
The Subsidiary had 10 full-time employees at the end of both 1996 and
1995. Consolidated payroll costs were $6.5 million in 1996 compared to
$6.8 million in 1995.
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 three-year contract effective January 1,
1995. Annual wage increases of 3.25% are provided in each year of the
contract.
Regulatory Proceedings
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 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 will apply only to the last two rate increases,
scheduled to occur 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 the
Wheelabrator-Sherman Energy Company (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, under the terms of the plan, has recognized write-offs
in 1995, totalling 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 seek
recovery of this deferred amount, up to a total of $6,000,000, in rates
beginning in the year 2001, after the current term of its contract with
Wheelabrator-Sherman has expired. The Company will once again attempt to
negotiate with Wheelabrator-Sherman to restructure the terms of its power
purchase contract, which was mandated by the MPUC acting under the
authority of Public Utility Regulatory Policy Act (PURPA). To date,
negotiations have not been successful. The Company believes the deferral
allowed under this rate plan parallels the accounting effects of a
restructured contract. The Company and Wheelabrator-Sherman are
continuing discussions, and the benefits of any restructured contract will
be passed through to the Company's customers, by applying any savings
first to these deferred amounts. The rate plan also allows 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 amortized over the rate
plan period.
The Company's success under the rate plan depends on the normal
operation of Maine Yankee. As discussed in the "Maine Yankee" section of
this Annual Report, the additional capacity payments required to address
issues raised in the Independent Safety Assessment and the replacement
power costs during unscheduled outages adversely impact the Company's
earnings and cash flows. Moreover, the Company's short-term revolving
credit agreement, as well as a letter of credit supporting its 1996
revenue bonds, contain
(Page 10)
interest coverage tests that the Company must satisfy to avoid default.
The Company now believes, based on the projected additional Maine Yankee
expenses and replacement power costs during the Plant outage, that it will
likely be in violation of these interest coverage tests for the twelve
months ended March 31, 1997. The Company will seek a waiver of these
requirements from the necessary parties, but cannot predict the terms of
any such waiver or whether they will be granted. Depending on the length
of the unscheduled outage to replace fuel assemblies and the inspection of
the Plant's electrical cabling, several provisions of the rate plan could
be triggered to permit retail rate increases in excess of those scheduled.
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 1997. The Company
cannot predict FERC's ultimate decision in this matter. The Company has
not recognized approximately $630,000 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.
Industry Restructuring
In 1995, the Maine Legislature passed Resolve 89 "To Require a Study
of Retail Competition in the Electric Utility Industry" (the Resolve), to
begin a process for developing recommendations on the future structure of
the electric utility industry in Maine. The process included the
appointment of a Work Group on Electric Utility Restructuring to develop a
plan for the orderly transition to a competitive market for retail
purchases and sales of electricity. The Company participated in this Work
Group, which was unable to reach a consensus on a recommended plan by its
reporting deadline.
The Resolve also directed the Maine Public Utilities Commission
(MPUC) to conduct a study to develop at least two plans for the orderly
transition to retail competition in the electric utility industry in Maine
and to submit a report of its findings by January 1, 1997. One plan would
be designed to achieve ". . . full retail market competition for purchases
and sales of electric energy by the year 2000" and the other to achieve a
more limited form of competition. The Resolve also stated that the MPUC's
findings would have no legal effect, but would ". . . provide the
Legislature with information in order to allow the Legislature to make
informal decisions when it evaluates these plans."
On December 31, 1996, the MPUC filed its recommended plan with the
Maine Legislature. Major provisions of the plan are as follows:
* As of January, 2000, all Maine consumers would have the option
to choose an electric power supplier in a competitive market.
* As of January, 2000, Maine would not regulate, as public
utilities, companies producing or selling electric power.
* Regulated public utilities would continue to provide electric
transmission and distribution services. These transmission and
distribution utilities would have exclusive service territories and an
obligation to connect customers to the power grid.
* As of January, 2000, the Company, Central Maine Power Company
(CMP) and Bangor Hydro-Electric Company (BHE), the State's three largest
electric utilities, would be required to structurally separate their
generation assets and functions from transmission and distribution
functions. CMP and BHE would be required to fully divest themselves of
their generation assets by 2006. The plan does not recommend generation
divestiture for the Company.
* All contracts between the utilities and any qualifying
facilities under PURPA will remain with the transmission and distribution
companies.
* The utilities should be provided a reasonable opportunity to
fully recover its generation-related stranded costs. All of the Company's
anticipated stranded costs are generation-related. Stranded costs would
be collected from customers through the regulated charges of the
transmission and distribution companies.
* Before 2000, the MPUC would consider progress in other
jurisdictions and at the regional level in making the decisions necessary
to implement retail competition.
* The MPUC would not require that other states or Canadian
provinces allow retail competition in their jurisdictions as a condition
to permitting suppliers from these states or provinces to enter Maine's
market.
* Maine Yankee's decommissioning liability would be collected in
the rates of the transmission and distribution utilities.
* Investor-owned transmission and distribution utilities would not
market power. While CMP and BHE could not have affiliates to market power
after 2005, the Company could have such an affiliate to market power but
only in its service territory.
The Maine Legislature will consider the plan during its current
session. The Company will be active in the debate on several elements of
the Plan. These elements include:
* The Company is entitled to full recovery of all stranded costs.
We must ensure that the MPUC defines
(Page 11)
methodologies that consistently and fairly determine asset values. In its
plan, based on various estimates of power costs, the MPUC estimated a
range of stranded costs for the Company from a negative $54 million to a
positive $83 million. A range of this magnitude indicates not only the
absence of a coherent methodology for estimating stranded costs, but also
the risk that the process can be manipulated to unfairly disadvantage the
Company's shareholders.
* Only suppliers operating in jurisdictions that allow retail
competition should be qualified to sell in Maine's competitive market.
Failure to insist on this reciprocity will give foreign suppliers an
unfair competitive advantage over Maine suppliers. A supplier operating
in a State or Canadian Province that has no retail competition will be
able to recover its fixed costs from its captive retail market and need
recover only its variable costs to successfully market its product in
Maine. Maine suppliers, on the other hand, will have to recover both
fixed and variable costs in order to compete successfully. Moreover,
those foreign suppliers will be able to "cherry pick" large industrial
customers or aggregated loads, while Maine suppliers, such as the Company,
will be barred from similar opportunities in those foreign markets.
Many parties to this proceeding have taken positions that vary
substantially from those set forth in the MPUC's plan, and those parties
are expected to advocate their positions before the Legislature.
Therefore, the Company cannot predict what form the restructuring of
Maine's electric utility industry will ultimately take or what effect that
restructuring will have on the Company's business operations and financial
results.
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; developments in our legislative, regulatory, and competitive
environment; and the results of safety investigations, the cost of
maintenance or the operating performance of Maine Yankee.
Shareholder Information
General
The Company's Common Stock is listed and traded on the American Stock
Exchange. As of December 31, 1996 and 1995, Common Stock shares issued
and outstanding were 1,617,250. As of December 31, 1996, shares were held
by 1,619 shareholders or nominees in forty-nine states, the District of
Columbia, Canada, 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 1996 Dividends
The Company has determined that the Common Stock dividends paid in
1996 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
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
1995
First Quarter $23-7/8 $20-5/8 $ .46 $ .46
Second Quarter $22-3/4 $19-7/8 .46 .46
Third Quarter $23-1/4 $21 .46 .46
Fourth Quarter $23-1/2 $20-5/8 .46 .46
Total Dividends $1.84 $1.84
Dividends declared within the quarter are paid on the first day of
the succeeding quarter.
(Page 12)
Five-Year Summary of Selected Financial Data
1996 1995 1994 1993 1992
Operating Revenues
$ 57,264,165 $ 55,278,726 $ 58,368,085 $ 60,476,212 $ 56,683,640
Income Before Extraordinary Items
$ 2,110,694 $ 920,500 $ 4,845,647 $ 5,300,840 $ 4,864,936
Extraordinary Items, Net of Taxes
- (6,235,812) - - -
Net Income (Loss) Available for Common Stock
$ 2,110,694 $ (5,315,312) $ 4,845,647 $ 5,300,840 $ 4,864,936
Earnings (Loss) Per Share of Common Stock
Income Before Extraordinary Items
$ 1.31 $ .57 $ 2.99 $ 3.19 $ 2.93
Extraordinary Items
- (3.86) - - -
Net Income (Loss)
$ 1.31 $ (3.29) $ 2.99 $ 3.19 $ 2.93
Dividends Per Share of Common Stock:
Declared Basis
$ 1.84 $ 1.84 $ 1.84 $ 1.78 $ 1.76
Paid Basis
$ 1.84 $ 1.84 $ 1.84 $ 1.76 $ 1.74
Total Assets
$116,714,374 $114,074,091 $122,375,442 $124,936,558 $112,047,613
Long-Term Debt Outstanding
$ 41,120,000 $ 37,435,000 $ 37,500,000 $ 39,365,000 $ 39,455,000
Less amount due within one year
1,315,000 1,315,000 65,000 1,865,000 90,000
Long-Term Debt
$ 39,805,000 $ 36,120,000 $ 37,435,000 $ 37,500,000 $ 39,365,000
(Page 13)
Independent Auditors' Report
MAINE PUBLIC SERVICE COMPANY:
We have audited the accompanying consolidated balance sheet and
statement of capitalization of Maine Public Service Company and its
Subsidiary, Maine and New Brunswick Electrical Power Company, Limited, as
of December 31, 1996, and the related consolidated statements of
operations, common shareholders' equity, and cash flows for the year 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 audit. The consolidated financial
statements of Maine Public Service Company and its Subsidiary for the
years ended December 31, 1995 and 1994, were audited by other auditors,
whose report dated February 14, 1996, expressed an unqualified opinion on
those statements.
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, the 1996 consolidated financial statements present
fairly, in all material respects, the consolidated financial position of
Maine Public Service Company and its Subsidiary at December 31, 1996 and
the results of their operations and their cash flows for the year then
ended in conformity with generally accepted accounting principles.
/s/ Coopers & Lybrand, LLP
Coopers & Lybrand LLP
Portland, Maine
February 11, 1997
(Page 14)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Statements of Consolidated Operations
Year Ended December 31,
1996 1995 1994
Operating Revenues $ 57,264,165 $ 55,278,726 $ 58,368,085
Operating Expenses
Purchased Power 31,819,691 31,978,290 27,764,353
Other Operation
and Maintenance 12,439,768 11,826,100 12,726,268
Depreciation and
Amortization 4,097,456 4,277,494 4,224,190
Taxes Other Than
Income 1,664,685 1,653,228 1,594,422
Provision for
Income Taxes 1,954,747 1,179,336 3,739,777
Total Operating Expenses
51,976,347 50,914,448 50,049,010
Operating Income 5,287,818 4,364,278 8,319,075
Other Income (Deductions)
Equity in Income of
Associated Companies 350,008 360,684 361,752
Allowance for Equity
Funds Used During
Construction 7,120 3,667 9,174
Provision for Income
Taxes (103,681) (73,269) (104,546)
Other - Net 95,678 27,172 113,925
Total 349,125 318,254 380,305
Income Before Interest
Charges and
Extraordinary Items 5,636,943 4,682,532 8,699,380
Interest Charges
Long-Term Debt and
Notes Payable 3,529,867 3,763,395 3,857,301
Less Allowance for
Borrowed Funds Used
During Construction (3,618) (1,363) (3,568)
Total 3,526,249 3,762,032 3,853,733
Income Before
Extraordinary Items 2,110,694 920,500 4,845,647
Extraordinary Items,
Net of Taxes of - (6,235,812) -
Net Income (Loss) Available
for Common Stock $2,110,694 $ (5,315,312) $4,845,647
Earnings (Loss) Per Share of Common Stock
Income Before
Extraordinary Items $ 1.31 $ .57 $ 2.99
Extraordinary Items - $ (3.86) -
Net Income (Loss) $ 1.31 $ (3.29) $ 2.99
Average Shares Outstanding 1,617,250 1,617,250 1,618,700
See Notes to Consolidated Financial Statements.
(Page 15)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Statements of Consolidated Cash Flows
Year Ended December 31,
1996 1995 1994
Cash Flow From Operating Activities
Net Income (Loss) $ 2,110,694 $(5,315,312) $ 4,845,647
Adjustments to Reconcile Net Income (Loss) to
Net Cash Provided by Operations:
Depreciation and
Amortization 4,097,456 4,277,494 4,224,190
Extraordinary Items, After
Income Taxes - 6,235,812 -
Deferred Income Taxes - Net
(377,355) 1,165,623 (359,942)
Deferred Investment Tax Credits
(74,662) (77,027) (77,027)
Allowance for Funds Used During Construction
(10,738) (5,030) (12,742)
Income on Tax-Exempt Bonds-Restricted Funds
(118,443) - (6,269)
Change in Deferred Regulatory and Debt Issuance Costs
(267,768) (4,795,603) 1,690,200
Change in Deferred Revenues
275,846 353,653 (119,440)
Change in Benefit Obligations
874,267 301,164 53,615
Change in Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenue
1,023,602 (246,124) 1,048,069
Deferred Fuel and Purchased Energy Cost
- 442,416 (760,990)
Other Current Assets
(366,995) 39,540 (216,035)
Accounts Payable
244,157 1,150,497 495,726
Accrued Taxes and Interest
(161,894) 11,374 (654,040)
Other Current Liabilities
(16,673) 4,291 (11,316)
Other - Net
153,205 (115,579) 153,136
Net Cash Flow Provided By Operating Activities
7,384,699 3,427,189 10,292,782
Cash Flow From Financing Activities
Dividend Payments (2,975,740) (2,975,740) (2,975,740)
Tax-Exempt Bond Issuance Costs
(398,585) - -
Purchase of Common Stock
- - (1,143,137)
Issuance of Tax-Exempt Bonds
15,000,000 - -
Drawdown of Tax-Exempt Bond Proceeds
1,063,969 - 1,110,637
Retirements of Long-Term Debt
(11,315,000) (65,000) (1,865,000)
Short-Term Borrowings, Net
- 1,400,000 -
Net Cash Flow Provided By (Used In) Financing Activities
1,374,644 (1,640,740) (4,873,240)
Cash Flow Used In Investing Activities
Investment in Restricted Funds
(5,000,000) - 169,588
Investment in Electric Plant
(3,444,515) (3,428,784) (4,362,620)
Net Cash Flow Used In Investing Activities
(8,444,515) (3,428,784) (4,193,032)
Increase (Decrease) in Cash and Temporary Investments
314,828 (1,642,335) 1,226,510
Cash and Temporary Investments at Beginning of Year
976,083 2,618,418 1,391,908
Cash and Temporary Investments at End of Year
$1,290,911 $ 976,083 $2,618,418
Supplemental Disclosure of Cash Flow Information:
Cash Paid During The Year For:
Interest $3,536,812 $3,499,198 $3,580,862
Income Taxes $2,939,776 $ 235,076 $5,040,950
See Notes to Consolidated Financial Statements.
(Page 16)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Consolidated Balance Sheets
Assets
December 31,
1996 1995
Utility Plant
Electric Plant in Service $91,224,297 $88,648,045
Less Accumulated Depreciation 41,670,398 39,674,322
Net Electric Plant in Service 49,553,899 48,973,723
Construction Work-In-Progress 461,435 427,654
Total 50,015,334 49,401,377
Investments in Associated Companies 3,658,627 3,641,211
Net Utility Plant and Investments in Associated Companies
53,673,961 53,042,588
Current Assets:
Cash and Temporary Investments 1,290,911 976,083
Deposits for Interest and Dividends 805,512 743,935
Accounts Receivable
(less allowance for uncollectible
accounts in 1996, $207,028 and
1995, $214,130) 5,020,921 6,225,423
Unbilled Revenue 1,652,720 1,471,820
Deferred Fuel and Purchased
Energy Costs 125,000 125,000
Current Deferred Income Taxes 221,578 232,269
Inventory 1,194,222 1,243,597
Prepayments 959,303 542,933
Total 11,270,167 11,561,060
Other Assets:
Recoverable Seabrook Costs (less
accumulated amortization and write-off
in 1996, $25,464,603; in 1995,
$24,040,971) 27,722,407 29,146,039
Regulatory Assets-SFAS 109 & 106 12,713,312 13,746,531
Restricted Investments (at cost, which
approximates market) 4,054,474 -
Deferred Fuel and Purchased Energy Costs 3,950,512 2,575,512
Unamortized Debt Expense (less
accumulated amortization
in 1996, $1,787,019; in
1995 $1,601,945) 936,376 702,865
Deferred Regulatory Costs (less
accumulated amortization
in 1996, $1,222,948; in 1995,
$1,567,429) 1,756,605 2,698,763
Miscellaneous 636,560 600,733
Total 51,770,246 49,470,443
Total Assets $116,714,374 $114,074,091
See Notes to Consolidated Financial Statements.
(Page 17)
Capitalization and Liabilities
December 31,
1996 1995
Capitalization (see accompanying statements):
Common Shareholders' Equity $38,091,749 $38,956,795
Long-Term Debt 39,805,000 36,120,000
Total 77,896,749 75,076,795
Current Liabilities:
Long-Term Debt Due Within One Year 1,315,000 1,315,000
Notes Payable to Banks 1,400,000 1,400,000
Accounts Payable 3,026,567 3,176,851
Accounts Payable -
Associated Companies 1,182,394 838,863
Accrued Employee Benefits 1,266,011 1,215,101
Dividends Declared 743,936 743,936
Customer Deposits 62,147 78,820
Taxes Accrued 135,759 105,634
Interest Accrued 826,684 1,018,703
Total 9,958,498 9,892,908
Deferred Credits:
Deferred Revenues 629,499 353,653
Income Taxes 23,694,229 24,997,851
Investment Tax Credits 720,473 795,135
Miscellaneous 3,814,926 2,957,749
Total 28,859,127 29,104,388
Commitments, Contingencies, and Regulatory Matters (Note 10)
Total Capitalization and Liabilities $116,714,374 $114,074,091
(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, 1994
1,660,250 $13,070,750 $38,317 $37,983,249 $(4,571,239)
Net Income 4,845,647
Dividends:
Common Stock ($1.84 per share) (2,975,740)
Stock Repurchased:
Common Stock
(43,000) (1,143,137)
Balance, December 31, 1994
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)
See Notes to Consolidated Financial Statements.
(Page 19)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Consolidated Statements of Capitalization
December 31,
1996 1995
Common Shareholders' Equity
Common Stock, $7 Par Value-Authorized
3,000,000 Shares in 1996 and 1995;
Issued 1,867,250 Shares in 1996 and 1995 $13,070,750 $13,070,750
Paid-In-Capital 38,317 38,317
Retained Earnings 30,697,058 31,562,104
Total 43,806,125 44,671,171
Treasury Stock-Total Shares of 250,000
in 1996 and 1995, at cost (5,714,376) (5,714,376)
Total $38,091,749 $38,956,795
Long-Term Debt
First Mortgage and Collateral Trust Bonds:
7-1/8% Due Serially through 1998-Interest Payable,
May 1 and November 1 $ 2,920,000 $ 2,960,000
7.95% Due Serially through 2003-Interest Payable,
March 1 and September 1 1,950,000 1,975,000
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 6,250,000 7,500,000
Public Utility Revenue Bonds-1991 Series:
7.875% Due 2021-Interest Payable,
April 1 and October 1 - 10,000,000
Public Utility Refunding Revenue Bonds-
Series 1996: Due 2021-Variable Interest
Payable Monthly (4.5% as of December 31, 1996) 15,000,000 -
Total Outstanding 41,120,000 37,435,000
Less-Amount Due Within One Year 1,315,000 1,315,000
Total $39,805,000 $36,120,000
Current Maturities and Redemption Requirements for the Succeeding Five
Years Are as Follows:
Long-Term Debt:
1997 $ 1,315,000
1998 $ 4,155,000
1999 $ 1,275,000
2000 $ 1,275,000
2001 $ 2,635,000
Thereafter $30,465,000
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, 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 $630,000 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
2.99%, 2.96%, and 2.99% for 1996, 1995, and 1994, respectively.
Bond issuance costs and premiums paid upon early retirements are
amortized over the terms of the related debt. Recoverable Seabrook costs
and 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 Temporary Investments
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 temporary investments.
Accounting Pronouncements
Effective January 1, 1996, the Company adopted Statement of Financial
Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of." The adoption of the
new standard had no effect on the Company's financial position or results
of operations.
Reclassifications
Certain reclassifications have been made to the 1995 and 1994
financial statements in order to conform to the 1996 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)".
1996 1995 1994
Current income taxes $2,510,445 $ 164,009 $4,281,292
Deferred income taxes (377,355) (687,190) (359,942)
Investment credits, net (74,662) (141,613) (77,027)
Total income taxes $2,058,428 $ (664,794) $3,844,323
Allocated to:
Operating income $1,954,747 $1,179,336 $3,739,777
Other income 103,681 73,269 104,546
Extraordinary Items - (1,917,399) -
Total $2,058,428 $ (664,794) $3,844,323
The effective income tax rates differ from the U.S. statutory rate as
follows:
1996 1995 1994
Statutory rate 34.0% (34.0)% 34.0%
Excess Canadian taxes 4.2 1.6 1.2
Amortization of recoverable
Seabrook costs 6.7 5.5 3.8
State income taxes 5.4 (1.7) 5.8
Seabrook wholesale write-off - 16.7 -
Other (.9) .8 (.6)
Effective rate 49.4% (11.1)% 44.2%
The elements of deferred income tax expense (credit) are as follows:
(Dollars in Thousands)
1996 1995 1994
Temporary Differences at
Statutory Rates:
Seabrook - costs $ (200) $ (234) $ (234)
Liberalized depreciation 166 219 158
AFUDC-borrowed funds (52) (63) (63)
Deferred fuel/Wheelabrator-
Sherman expenses 559 582 328
Deferred regulatory expense (345) 829 (573)
Unbilled and deferred revenue (110) (141) 48
Accrued pension and post-
retirement benefits (414) 40 52
Other 19 (66) (76)
Total temporary differences
- operations (377) 1,166 (360)
Extraordinary Items - (1,853) -
Total temporary differences
- statutory rates $ (377) $ (687) $ (360)
(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
1995, while dividends were $433,243 and $736,492 in 1994 and 1996,
respectively. In 1994, the dividend received from the Subsidiary exceeded
earnings by $55,816, while for 1996, earnings exceeded the dividend by
$8,608.
The following summarizes accumulated deferred income taxes
established on temporary differences under SFAS 109 as of December 31,
1996 and 1995.
(Dollars in Thousands)
1996 1995
Seabrook $15,273 $16,071
Property 8,104 8,396
Regulatory expenses 1,201 915
Investment tax credits (478) (528)
Pension and post-
retirement benefits (670) (262)
Other 264 406
Net accumulated deferred
income taxes $23,694 $24,998
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".
Dividends received during 1996, 1995, and 1994 from Maine Yankee were
approximately $333,750, $172,500, and $347,500, respectively, and from
MEPCO approximately $7,900 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
1996 1995 1994 1996 1995 1994
Earnings
Operating revenues
$185,661 $205,977 $173,857 $ 55,391 $ 49,699 $ 24,746
Earnings applicable to
Common Stock
$ 6,640 $ 7,060 $ 7,080 $ 220 $ 105 $ 105
Company's equity share
of net earnings
$ 332 $ 353 $ 354 $ 16 $ 8 $ 8
Investment
Total assets
$602,061 $580,958 $549,910 $ 10,727 $ 6,025 $ 6,562
Less:
Preferred stock
18,000 18,600 19,200 - - -
Long-term debt
83,332 89,999 96,666 620 - 1,730
Other liabilities and
deferred credits
429,392 401,158 366,550 9,110 5,147 3,954
Net assets
$ 71,337 $ 71,201 $ 67,494 $ 997 $ 878 $ 878
Company's equity in
net assets
$ 3,567 $ 3,560 $ 3,375 $ 75 $ 66 $ 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,
1996 and 1995 is as follows:
(Dollars in Thousands)
1996 1995
Electric plant in service $5,924 $5,896
Accumulated depreciation (3,231) (3,078)
Net electric plant in service $2,693 $2,818
5. SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit arrangement with a consortium of
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
plus 1/2%. The B Loans bear interest as arranged between the Company and
the participating bank. As of December 31, 1996 and 1995, a B Loan for
$1.4 million was outstanding under this arrangement at 5.5625% and 6.4%,
respectively.
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 1996.
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
1996, 1995, and 1994 plan years, the Company has made contributions of
$282,000 in 1997, $284,000 in 1996, and $340,000 in 1995, 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 1996, 1995, and 1994 are
as follows:
(Dollars in Thousands)
1996 1995 1994
Service costs for benefits
earned during the period $ 298 $ 264 $ 329
Interest cost on projected
benefit obligation 939 932 891
Return on plan assets:
Actual (1,251) (2,021) 83
Deferred 298 1,111 (962)
Total (953) (910) (879)
Net amortization
and deferral (2) (2) (2)
Net Pension Cost 282 284 339
Early retirement benefits 402 231 -
Total Pension Costs $ 684 $ 515 $ 339
The following table sets forth the plan's funded status, obligations,
and assumptions as of December 31, 1996 and 1995:
(Dollars in Thousands)
1996 1995
Accumulated benefit obligation:
Vested $ 11,016 $ 11,311
Non-vested 153 230
Total $ 11,169 $ 11,541
Projected benefit obligation $(13,041) $(13,949)
Fair value of assets 13,067 12,421
Funded status 26 (1,528)
Unrecognized prior
service costs 892 968
Unrecognized transition
amount (481) (558)
Unrecognized (gain) loss (2,008) (52)
Accrued Pension Cost $(1,571) $(1,170)
Assumptions:
Discount rate 7.5% 7.0%
Salary increases 4.5% 4.5%
Expected return on assets 8.5% 8.5%
At December 31, 1996, 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 $54,000, $41,000 and
$34,000 in 1996, 1995, and 1994, 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 1996.
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)
1996 1995 1994
Service costs for benefits $ 98 $ 97 $ 91
Interest cost 321 365 307
Amortization of transition
obligation 213 213 213
Total costs 632 675 611
Current payments for retiree
obligations
allowed in Company's cost
of service (233) (207) (195)
Additional SFAS 106 costs $399 $468 $416
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)
1996 1995
Retirees $(2,283) $(2,382)
Fully eligible actives (1,295) (1,300)
Other actives (892) (1,518)
Accumulated postretirement
benefit obligation (4,470) (5,200)
Transition obligation 3,394 3,607
Net (gain) loss (762) 154
Accrued postretirement benefit cost $(1,838) $(1,439)
There were no unrecognized prior service costs. For 1996 and 1995,
the Company used an assumed weighted average discount rate of 7.5% and 7%,
respectively. The health care cost trend rate used for 1996 was 8%, with
the ultimate trend rate of 5% reached in three 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 $642,000, in service costs by $31,000 and interest
costs by $48,000.
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 $30,697,058 at December 31, 1996.
8. REFINANCING
On April 4, 1991, the Maine Public Utilities Financing Bank (MPUFB)
issued $10 million of tax-exempt bonds (the 1991 Series) on behalf of the
Company. Pursuant to a letter of credit and reimbursement agreement, the
Company caused a Direct Pay Letter of Credit for a term of five years to
be issued by Barclays Bank PLC, New York Branch (Barclays Bank) for the
benefit of the holders of such bonds. To secure the Company's obligations
under the reimbursement agreement, the Company issued a second mortgage
bond to Barclays Bank as collateral for the Company's obligation. The
bonds had a coupon rate of 7.875% and, after considering the enhancement
fees and other costs, the annual cost to the Company was approximately
8.725%. In September 1995, Barclays Bank notified the Company that it
would not renew the Direct Pay Letter of Credit for this issue.
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 1991 Series through the payment of the refunding
note from Fleet Bank of Maine, used to redeem the 1991 Series, and
provides $5 million for the acquisition of qualifying property, of which
$4.1 million remains in trust as of December 31, 1996. 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
initially selected the weekly interest period. After considering issuance
costs and credit enhancement fees, the effective interest rate was 5.61%
for 1996.
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, 1996, the Company's long-term debt
had a carrying value of approximately $41.1 million and a fair value of
approximately $43.7 million.
(Page 25)
10. COMMITMENTS, CONTINGENCIES, AND
REGULATORY MATTERS
Customer Rates
On November 13, 1995, the Maine Public Utilities Commission (MPUC)
approved a stipulation establishing a four-year rate plan. Under the
terms of the stipulation, the Company's retail rates increased by 4.4% on
January 1, 1996 and 2.9% on February 1, 1997, and will increase by 2.75%
on February 1, 1998, and February 1, 1999, respectively. The Company has
agreed to seek no other increase, for either base or fuel rates, except as
provided under the terms of the rate plan. For the increases scheduled to
occur in 1998 and 1999, a profit-sharing mechanism based on a target
return on equity of 11%, calculated using certain retail ratemaking
methodologies, will also apply. 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. However, the Company is permitted to adjust the
annual increases for certain mandated costs, such as tax or accounting
changes that exceed $300,000 in annual revenue requirements. The plan
also provides that if either Maine Yankee or Wheelabrator-Sherman ceases
operations for more than six months, one-half of the resulting net costs
or net savings will adjust the allowed rate increases. Any net costs or
net savings realized during the first six months of the outage accrues
entirely to the shareholders. 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 plan.
Under the terms of the rate plan, the Company agreed to write off to
operating expenses $2,104,000, net of income taxes, of deferred retail
fuel representing replacement power costs incurred during the 1995 Maine
Yankee outage. As a result of the application of SFAS No. 101 "Accounting
for the Discontinuation of Application of FASB Statement No. 71", the
Company wrote off approximately $4,846,000, net of income taxes, of the
Company's investment in the Seabrook nuclear power project previously
allocated to the wholesale customers and $1,390,000, net of income taxes,
of other wholesale plant and regulatory assets.
The plan also permits the Company to annually defer $1.5 million 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 seek
recovery of this deferred amount, up to a total of $6 million, in rates
beginning in the year 2001, after the current term of its contract with
Wheelabrator-Sherman expires. The rate plan also allows the deferral,
until the year 2000, of approximately $1.3 million, net of taxes, of
uncollected retail fuel at the beginning of the rate plan, while an
additional $300,000, net of income taxes, will be amortized over the rate
plan period.
The Company's success under the rate plan depends on the normal
operation of Maine Yankee. The additional capacity payments required to
address issues raised in the Independent Safety Assessment and the
replacement power costs during unscheduled outages adversely impact the
Company's earnings and cash flows. Moreover, the Company's short-term
revolving credit agreement, as well as a letter of credit supporting its
1996 revenue bonds, contain interest coverage tests that the Company must
satisfy to avoid default. The Company now believes, based on the
projected additional Maine Yankee expenses and replacement power costs
during the Plant outage, that it will likely be in violation of these
interest coverage tests for the twelve months ended March 31, 1997. The
Company will seek a waiver of these requirements from the necessary
parties, but cannot predict the terms of any such waiver or whether they
will be granted. Depending on the length of the unscheduled outage to
replace fuel assemblies and the inspection of the Plant's electrical
cabling and steam generators, several provisions of the rate plan could be
triggered to permit retail rate increases in excess of those scheduled.
During outages, the Company incurs approximately $170,000 of additional
purchase power costs per week.
During 1996, the Company entered long-term power contracts with two
of its largest customers. The price under these contracts are lower than
permitted under the Company's standard rates, but obligates them to
purchase all of their electrical requirements through the year 2000. One
additional customer has signed a similar agreement that must be approved
by the MPUC, while two others have verbally accepted the Company's offers.
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.
Competition and Industry Restructuring
In 1995, the Maine Legislature passed Resolve 89 "To Require a Study
of Retail Competition in the Electric Utility Industry" (the Resolve), to
begin a process for developing recommendations on the future structure of
the electric utility industry in Maine. The process included the
appointment of a Work Group on Electric Utility Restructuring to develop a
plan for the orderly transition to a competitive market for retail
purchases and sales of electricity.
The Resolve also directed the Maine Public Utilities Commission
(MPUC) to conduct a study to develop at least two plans for the orderly
transition to retail competition in the electric utility industry in Maine
and to submit a report of its findings by January 1, 1997. One plan would
be designed to achieve ". . . full retail market competition for purchases
and sales of electric energy by the year 2000" and the other to achieve a
more limited form of competition. The Resolve also stated that the MPUC's
findings would have no legal effect, but would ". . . provide the
Legislature with information in order to allow the Legislature to make
informal decisions when it evaluates these plans."
On December 31, 1996, the MPUC filed its recommended plan with the
Maine Legislature. Major provisions of the plan are as follows:
* As of January, 2000, all Maine consumers would have the
option to choose an electric power supplier in a competitive market.
* As of January, 2000, Maine would not regulate, as public
utilities, companies producing or selling electric power.
* Regulated public utilities would continue to provide
electric transmission and distribution services. These transmission and
distribution utilities would have exclusive service territories and an
obligation to connect customers to the power grid.
* As of January, 2000, the Company, Central Maine Power
Company (CMP) and Bangor Hydro-Electric Company (BHE), the State's three
largest electric utilities, would be required to structurally separate
their generation assets and functions from transmission and distribution
functions. CMP and BHE would be required to fully divest themselves of
their generation assets by 2006. The plan does not recommend generation
divestiture for the Company.
(Page 26)
* All contracts between the utilities and any qualifying
facilities under PURPA will remain with the transmission and distribution
companies.
* The utilities should be provided a reasonable opportunity
to fully recover its generation-related stranded costs. All of the
Company's anticipated stranded costs are generation-related. Stranded
costs would be collected from customers through the regulated charges of
the transmission and distribution companies.
* Before 2000, the MPUC would consider progress in other
jurisdictions and at the regional level in making the decisions necessary
to implement retail competition.
* The MPUC would not require that other states or Canadian
provinces allow retail competition in their jurisdictions as a condition
to permitting suppliers from these states or provinces to enter Maine's
market.
* Maine Yankee's decommissioning liability would be collected
in the rates of the transmission and distribution utilities.
* Investor-owned transmission and distribution utilities
would not market power. While CMP and BHE could not have affiliates to
market power after 2005, the Company could have such an affiliate to
market power but only in its service territory.
Many parties to this proceeding have taken positions that vary
substantially from those set forth in the MPUC's plan, and those parties
are expected to advocate their positions before the Legislature.
Therefore, the Company cannot predict what form the restructuring of
Maine's electric utility industry will ultimately take or what effect that
restructuring will have on the Company's business operations and financial
results.
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, 1996 and 1995 are as follows:
(Dollars in Thousands)
1996 1995
Retail $43,136 $43,136
Accumulated Amortization (15,414) (13,990)
Retail, Net $27,722 $29,146
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 $3.6 million or $.5 million
annually, without considering inflation indexing.
Capacity Arrangements
The Company owns 5% of the Common Stock of the Maine Yankee Atomic
Power Company (Maine Yankee). Maine Yankee owns and operates an 860,000
kilowatt nuclear generating plant in Wiscasset, Maine. The Company is
entitled to purchase approximately 4.9% of the energy produced by the
Plant. During 1996, 1995, and 1994, Maine Yankee purchased power expenses
were $10,185,000, $7,972,000, and $9,645,000, respectively. During most
of 1995, Maine Yankee was not in service in order to repair its steam
generator tubes using welded sleeves. The sleeving of the steam generator
tubes was completed in mid-December of 1995 at a cost of approximately $27
million, with the Company's share being approximately $1.3 million. In
accordance with the Company's rate plan, discussed previously, the Company
began recovering these costs over five years starting in 1996. After
responding to allegations regarding certain safety analyses performed to
increase the rated capacity of the Plant, the Nuclear Regulatory
Commission (NRC) informed Maine Yankee that the allegations would be
subject to investigations, but allowed Maine Yankee to operate at 90% of
its rated maximum capacity until the NRC reviewed and approved
plant-specific analyses. On January 22, 1996, Maine Yankee attained the
90% level of the Plant's capability. Maine Yankee was out of service a
total of thirteen weeks in 1996 because of the January outage, a six-week
unscheduled outage in July and August, and the current outage that began
on December 6, 1996. The Plant is expected to remain out of service
through the summer of 1997 to allow the review and resolution of several
cable separation and cable routing issues and the replacement of 68 of the
Plant's 217 fuel assemblies due to the detection of minor leakages in a
small number of the Plant's fuel rods. In addition, 24 fuel assemblies
will be replaced as part of a refueling. These issues were discovered as
a result of the NRC's "Independent Safety Assessment" (ISA) and subsequent
internal investigation. The Company's share of expenses to address these
issues is approximately $2.3 million in 1997 for additional employees,
training, and equipment. The Company incurs approximately $170,000 per
week for replacement power costs while Maine Yankee is out of service. On
January 29, 1997, the NRC announced that it had placed the Plant on its
"watch list" in "Category 2", which includes plants that display
"weaknesses that warrant increased attention", but do not warrant a
shut-down order. The Plant is one of 14 nuclear units in the United
States on the January 19, 1997, "watch list" and one of six listed for the
first time.
Moreover, the Company's short-term revolving credit agreement, as
well as a letter of credit supporting its 1996 Series of tax-exempt bonds,
contain interest coverage tests that the Company must satisfy to avoid
default. The Company now believes, based on the projected additional
Maine Yankee expenses and replacement power costs during the Plant outage,
that it will likely be in violation of these interest coverage tests for
the twelve months ended March 31, 1997. The Company will seek a waiver of
these requirements from the necessary parties. The Company anticipates
that the waiver will be granted, but cannot predict the terms of any such
waiver.
As an owner of Maine Yankee, the Company is responsible for its
proportional share of Maine Yankee operating expenses, including fuel and
decommissioning expenses. Furthermore, under a Capital Funds Agreement,
the Company, along with the other sponsoring utilities, has agreed to
provide Maine Yankee's capital requirements which cannot be obtained from
other sources. This obligation is limited to each owner's interest in
Maine Yankee, subject to obtaining necessary regulatory approvals.
In 1994, pursuant to FERC authorization, Maine Yankee increased its
annual collection for decommissioning to $14.9 million, approximately
$735,000 a year for the Company. This increase was
(Page 27)
based on a new decommissioning estimate, assuming dismantlement and
removal, of $317 million (in 1993 dollars), as a result of an external
engineering study. As of December 31, 1996, Maine Yankee's
decommissioning funds are valued at $163.5 million. The decommissioning
of nuclear power plants is subject to changes in legal and regulatory
requirements as well as technological changes.
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.
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 Maine Yankee and 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., owner of an 18 megawatt wood-burning cogenerator plant, began selling
power to the Company. The Company purchases the entire output from the
cogenerator under a contract ordered by the MPUC that will expire in 2001.
This contract includes a 5% annual price increase. During 1996, 1995, and
1994, purchases from Wheelabrator-Sherman were $15,593,000, $14,507,000,
and $13,932,000, respectively.
Construction Program
Expenditures on additions, replacements and equipment for the years
ended December 31, 1996, 1995, and 1994, along with 1997 estimated
expenditures, are as follows:
(Dollars in Thousands) 1997 1996 1995 1994
(Unaudited Estimates)
Parent Company
Generation $ 69 $ 345 $ 131 $ 178
Transmission 420 322 364 357
Distribution 2,032 2,080 1,993 2,235
General 417 626 845 1,015
Total Parent 2,938 3,373 3,333 3,785
Subsidiary 131 72 96 578
Total $3,069 $3,445 $3,429 $4,363
11. QUARTERLY INFORMATION (unaudited)
Quarterly financial data for the two years ended December 31, 1996
is as follows:
(Dollars in Thousands Except Per Share Amounts)
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 $ .90 $ .38 $ (.41) $ .44
1995 by Quarter
1st 2nd 3rd 4th
Operating revenues $15,556 $12,471 $12,273 $14,947
Operating expenses (13,801) (10,589) (10,857) (15,635)
Operating income 1,755 1,882 1,416 (688)
Interest charges (943) (939) (938) (942)
Other income-net 62 63 111 82
Income (loss) before
extraordinary items 874 1,006 589 (1,548)
Extraordinary items - - - (6,236)
Net income (loss) $ 874 $ 1,006 $ 589 $(7,784)
Earnings (loss) per common share
Income (loss) before extra-
ordinary items $ .54 $ .62 $ .36 $ (.95)
Extraordinary items - - - (3.86)
Net income (loss) $ .54 $ .62 $ .36 $ (4.81)
(Page 28 & 29)
MAINE PUBLIC SERVICE COMPANY
and Subsidiary
All share information and per share amounts reflect the stock split on
March 3, 1989.
Consolidated Financial Statistics
1996 1995 1994
Capitalization Including Bank
Borrowings (year-end)
Debt (including amount due
within one year) 52.75% 49.92% 44.25%
Preferred Stock (including
amount due
within one year) 0% 0% 0%
Common Shareholders' Equity 47.25% 50.08% 55.75%
Times Interest Earned - *
Before Income Taxes 2.18 2.51 3.25
After Income Taxes 1.60 1.80 2.26
Times Interest and Preferred
Dividends Earned - *
After Income Taxes 1.60 1.80 2.26
Embedded Cost of Long-Term
Debt (year-end) 8.01% 9.36% 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
Earnings Per Share of Common
Stock (average shares)
Income Before Cumulative Effect
of Accounting Change and Extra-
ordinary Items 1.31 .57 2.99
Cumulative Effect of
Accounting Change - - -
Extraordinary Items - (3.86) -
Net Income (Loss) 1.31 (3.29) 2.99
Dividends Per Share of Common Stock
Declared Basis 1.84 1.84 1.84
Paid Basis l.84 l.84 l.84
Common Stock Dividend
Payout Ratio - ** 140.46% 98.40% 61.54%
Book Value Per Share of
Common Stock (year-end) 23.55 24.09 29.22
Market Price Per Share of
Common Stock
High 22 3/8 23 7/8 27 3/8
Low 16 7/8 19 7/8 20 1/2
Close 18 1/8 21 3/8 20 3/4
Price Earnings Ratio (year-end) 13.84 - 6.94
Number of Common Shareholders
(year-end) 1,619 1,634 1,650
* Consolidated income before cumulative effect of accounting change and
extraordinary items. Includes AFUDC and Deferred Return on Seabrook
Investment. Excludes all Seabrook write-offs in 1985 and 1986 and all
regulatory write-offs in 1995.
** Before regulatory write-offs in 1995.
Consolidated Financial Statistics
1993 1992 1991
Capitalization Including Bank
Borrowings (year-end)
Debt (including amount due
within one year) 45.83% 50.16% 53.01%
Preferred Stock (including
amount due within one year) 0% 0% 0%
Common Shareholders' Equity 54.17% 49.84% 46.99%
Times Interest Earned - *
Before Income Taxes 3.49 3.01 2.81
After Income Taxes 2.36 2.09 2.00
Times Interest and Preferred
Dividends Earned - *
After Income Taxes 2.36 2.09 2.00
Embedded Cost of Long-Term
Debt (year-end) 9.14% 9.14% 9.28%
Embedded Cost of Preferred
Stock (year-end) 0% 0% 0%
Common Shares Outstanding
(year-end) 1,660,250 1,660,250 1,660,250
Earnings Per Share of Common
Stock (average shares)
Income Before Cumulative Effect
of Accounting
Change and Extraordinary Items 3.19 2.93 2.62
Cumulative Effect of Accounting
Change - - -
Extraordinary Items - - -
Net Income (Loss) 3.19 2.93 2.62
Dividends Per Share of Common Stock
Declared Basis 1.78 1.76 1.68
Paid Basis l.76 1.74 1.68
Common Stock Dividend
Payout Ratio - ** 55.80% 60.07% 64.12%
Book Value Per Share of Common
Stock (year-end) 28.02 26.61 25.44
Market Price Per Share of
Common Stock
High 31 1/4 26 7/8 26 3/8
Low 25 5/8 24 1/4 20 3/4
Close 25 7/8 25 7/8 26 3/8
Price Earnings Ratio (year-end) 8.11 8.83 10.07
Number of Common Shareholders
(year-end) 1,720 1,768 1,823
* Consolidated income before cumulative effect of accounting change and
extraordinary items. Includes AFUDC and Deferred Return on Seabrook
Investment. Excludes all Seabrook write-offs in 1985 and 1986 and all
regulatory write-offs in 1995.
** Before regulatory write-offs in 1995.
Consolidated Financial Statistics (Continued)
1990 1989 1988
Capitalization Including Bank
Borrowings (year-end)
Debt (including amount due
within one year) 49.40% 43.12% 47.76%
Preferred Stock (including
amount due within one year) 0% 4.02% 4.41%
Common Shareholders' Equity 50.60% 52.86% 47.83%
Times Interest Earned - *
Before Income Taxes 3.24 3.21 3.07
After Income Taxes 2.22 2.26 2.29
Times Interest and Preferred
Dividends Earned - *
After Income Taxes 2.18 2.09 2.05
Embedded Cost of Long-Term Debt
(year-end) 9.92% 9.71% 10.80%
Embedded Cost of Preferred Stock
(year-end) 0% 9.74% 9.74%
Common Shares Outstanding
(year-end) 1,761,050 1,849,550 1,865,666
Earnings Per Share of Common Stock (average shares)
Income Before Cumulative Effect of Accounting
Change and Extraordinary
Items 2.58 2.71 3.12
Cumulative Effect of Accounting
Change - - -
Extraordinary Items - - -
Net Income (Loss) 2.58 2.71 3.12
Dividends Per Share of Common Stock
Declared Basis 1.68 1.575 1.175
Paid Basis 1.66 1.55 1.025
Common Stock Dividend Payout
Ratio - ** 65.12% 58.12% 37.66%
Book Value Per Share of Common
Stock (year-end) 24.38 23.39 22.26
Market Price Per Share of
Common Stock
High 23 3/8 24 7/8 20 13/16
Low 19 1/2 20 5/16 11 7/8
Close 22 1/4 22 3/8 20 1/2
Price Earnings Ratio (year-end) 8.62 8.26 6.57
Number of Common Shareholders
(year-end) 2,061 1,919 1,933
* Consolidated income before cumulative effect of accounting change and
extraordinary items. Includes AFUDC and Deferred Return on Seabrook
Investment. Excludes all Seabrook write-offs in 1985 and 1986 and all
regulatory write-offs in 1995.
** Before regulatory write-offs in 1995.
Consolidated Financial Statistics (Continued)
1987 1986
Capitalization Including Bank Borrowings
(year-end)
Debt (including amount due within one year) 49.32% 55.97%
Preferred Stock (including amount due
within one year) 8.32% 7.92%
Common Shareholders' Equity 42.36% 36.11%
Times Interest Earned - *
Before Income Taxes 2.27 2.31
After Income Taxes 1.69 1.92
Times Interest and Preferred Dividends
Earned - *
After Income Taxes 1.49 1.73
Embedded Cost of Long-Term Debt (year-end) 10.98% 11.56%
Embedded Cost of Preferred Stock (year-end) 11.20% 11.12%
Common Shares Outstanding (year-end) 1,862,478 1,858,472
Earnings Per Share of Common Stock
(average shares)
Income Before Cumulative Effect of
Accounting Change & Extraordinary Items 1.59 3.43
Cumulative Effect of Accounting Change .45 -
Extraordinary Items - (1.38)
Net Income (Loss) 2.04 2.05
Dividends Per Share of Common Stock
Declared Basis .80 .525
Paid Basis .75 .35
Common Stock Dividend Payout Ratio - ** 39.22% 25.60%
Book Value Per Share of Common Stock (year-end) 20.41 19.18
Market Price Per Share of Common Stock
High 15 7/16 16
Low 11 1/2 9 3/4
Close 12 9/16 14 1/16
Price Earnings Ratio (year-end) 6.16 6.86
Number of Common Shareholders (year-end) 2,045 2,188
* Consolidated income before cumulative effect of accounting change and
extraordinary items. Includes AFUDC and Deferred Return on Seabrook
Investment. Excludes all Seabrook write-offs in 1985 and 1986 and all
regulatory write-offs in 1995.
** Before regulatory write-offs in 1995.
1996 Sources of Income
Millions of Dollars (Total $57.6)
and Percent of Total
Other Income -- $2.7 Million [4.7%]
Residential -- $20.0 Million [34.7%]
Commercial -- $16.4 Million [28.5%]
Industrial -- $10.1 Million [17.5%]
Other Electric Sales -- $8.4 Million [14.6%]
1996 Distribution of Income
Millions of Dollars (Total $57.6)
and Percent of Total
Retained Earnings -- $(.9) Million [(1.6%)]
Fuel & Purchased Power -- $31.8 Million [55.2%]
Wages and Employee Benefits -- $6.9 Million [12.0%]
Taxes -- $3.7 Million [6.4%]
Other Operating Expenses -- $9.6 Million [16.7%]
Interest -- $3.5 Million [6.1%]
Common Dividends -- $3.0 Million [5.2%]
(Pages 30-31)
MAINE PUBLIC SERVICE COMPANY
and Subsidiary
Consolidated Operating Statistics
1996 1995 1994
Operating Revenues
Residential $19,961,192 $19,080,662 $19,646,681
Commercial and Industrial
- Small 16,420,167 15,723,439 15,614,453
Commercial and Industrial
- Large 10,111,758 9,437,409 9,225,131
Municipal Street Lighting 538,890 524,616 517,793
Area Lighting 273,985 272,896 271,115
Other Municipal and Other
Public Authorities 710,106 903,370 2,105,933
Other Electric Utilities 6,893,598 7,573,360 8,481,483
Other Operating Revenues
(Revenue Adjustments) 2,354,469 1,762,974 2,505,496
Total Operating Revenues $57,264,165 $55,278,726 $58,368,085
Number of Customers (average)
Residential 28,515 28,385 28,300
Commercial and Industrial
- Small 5,541 5,465 5,418
Commercial and Industrial
- Large 15 15 16
Municipal Street Lighting 38 38 38
Area Lighting 1,059 1,048 1,048
Other Municipal and Other
Public Authorities 5 5 8
Other Electric Utilities 10 9 9
Total Customers 35,183 34,965 34,837
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 10,201 22,867 18,559
Hydro 168,993 121,252 118,759
Diesel (674) 1,046 (153)
Purchases:
Nuclear Generated 249,083 9,718 326,334
Fossil Fuel Generated 372,431 508,266 290,172
Inadvertent Received
(Delivered) 741 (1,449) 651
Total 800,775 661,700 754,322
Losses, Unaccounted for
and Unbilled 33,303 36,411 42,880
Company Use 1,517 1,490 1,518
Electricity Sold 765,955 623,799 709,924
Sales:
Residential 169,298 168,640 175,685
Commercial and Industrial
- Small 163,804 165,914 167,485
Commercial and Industrial
- Large 134,588 128,478 127,327
Municipal Street Lighting 1,658 1,655 1,642
Area Lighting 1,418 1,457 1,472
Other Municipal and Other
Public Authorities 10,090 11,747 28,621
Other Electric Utilities 285,099 145,908 207,692
Total Sales 765,955 623,799 709,924
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 5,937 5,941 6,208
Revenue $700.02 $672.21 $694.23
Revenue per Kilowatt-hour 11.79 cents 11.31 cents 11.18 cents
Consolidated Operating Statistics
1993 1992 1991
Operating Revenues
Residential $19,669,749 $18,704,900 $19,194,469
Commercial and Industrial
- Small 15,177,992 13,787,720 13,991,693
Commercial and Industrial
- Large 9,554,566 8,891,123 10,105,693
Municipal Street Lighting 512,439 499,814 512,640
Area Lighting 269,925 261,984 267,518
Other Municipal and Other
Public Authorities 3,597,514 3,761,815 3,977,098
Other Electric Utilities 9,188,561 8,150,094 7,328,914
Other Operating Revenues
(Revenue Adjustments) 2,505,466 2,626,190 2,460,062
Total Operating Revenues $60,476,212 $56,683,640 $57,838,087
Number of Customers (average)
Residential 28,220 28,102 28,052
Commercial and Industrial
- Small 5,364 5,261 5,205
Commercial and Industrial
- Large 16 15 15
Municipal Street Lighting 38 38 38
Area Lighting 1,061 1,075 1,091
Other Municipal and Other
Public Authorities 8 8 8
Other Electric Utilities 8 7 7
Total Customers 34,715 34,506 34,416
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 26,456 33,509 28,868
Hydro 148,719 130,407 135,619
Diesel 169 (636) (178)
Purchases:
Nuclear Generated 282,199 263,313 307,769
Fossil Fuel Generated 288,487 300,930 246,172
Inadvertent Received
(Delivered) (1,053) (2,232) 1,861
Total 744,977 725,291 720,111
Losses, Unaccounted for
and Unbilled 43,944 43,686 42,114
Company Use 1,542 1,462 1,499
Electricity Sold 699,491 680,143 676,498
Sales:
Residential 176,732 176,814 176,028
Commercial and Industrial
- Small 162,949 155,267 149,709
Commercial and Industrial
- Large 135,029 129,981 139,931
Municipal Street Lighting 1,630 1,864 2,336
Area Lighting 1,482 1,538 1,591
Other Municipal and Other
Public Authorities 53,021 58,388 57,687
Other Electric Utilities 168,648 156,291 149,216
Total Sales 699,491 680,143 676,498
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 6,263 6,292 6,275
Revenue $697.01 $665.61 $684.25
Revenue per Kilowatt-hour 11.13 cents 10.58 cents 10.90 cents
Consolidated Operating Statistics
1990 1989 1988
Operating Revenues
Residential $18,189,325 $18,537,902 $17,787,713
Commercial and Industrial
- Small 12,708,677 13,379,207 12,374,719
Commercial and Industrial
- Large 10,115,772 9,785,058 9,673,266
Municipal Street Lighting 505,063 573,351 559,478
Area Lighting 262,845 288,378 285,979
Other Municipal and Other
Public Authorities 3,611,220 3,736,851 3,546,473
Other Electric Utilities 9,649,398 10,980,817 9,244,874
Other Operating Revenues
(Revenue Adjustments) 1,701,167 (62,314) 649,746
Total Operating Revenues $56,743,467 $57,219,250 $54,122,248
Number of Customers (average)
Residential 27,983 27,737 27,358
Commercial and Industrial
- Small 5,108 4,940 4,866
Commercial and Industrial
- Large 15 17 18
Municipal Street Lighting 38 38 37
Area Lighting 1,114 1,155 1,166
Other Municipal and Other
Public Authorities 8 8 8
Other Electric Utilities 7 8 7
Total Customers 34,273 33,903 33,460
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 59,252 91,361 81,583
Hydro 176,832 106,571 112,953
Diesel (186) 2,664 1,933
Purchases:
Nuclear Generated 253,321 369,315 266,851
Fossil Fuel Generated 289,177 217,166 299,838
Inadvertent Received
(Delivered) (151) 1,611 (677)
Total 778,245 788,688 762,481
Losses, Unaccounted for
and Unbilled 40,613 42,474 44,883
Company Use 1,559 1,723 1,555
Electricity Sold 736,073 744,491 716,043
Sales:
Residential 178,011 178,668 176,680
Commercial and Industrial
- Small 146,881 145,364 139,220
Commercial and Industrial
- Large 155,782 145,307 148,220
Municipal Street Lighting 2,697 2,722 2,695
Area Lighting 1,643 1,580 1,585
Other Municipal and Other
Public Authorities 57,034 59,190 59,268
Other Electric Utilities 194,025 211,660 188,375
Total Sales 736,073 744,491 716,043
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 6,361 6,442 6,458
Revenue $650.01 $668.35 $650.18
Revenue per Kilowatt-hour 10.22 cents 10.38 cents 10.07 cents
Consolidated Operating Statistics (Continued)
1987 1986
Operating Revenues
Residential $15,948,095 $15,641,623
Commercial and Industrial - Small 10,700,466 10,077,605
Commercial and Industrial - Large 7,736,051 8,468,298
Municipal Street Lighting 541,853 526,156
Area Lighting 273,570 285,856
Other Municipal and Other
Public Authorities 2,955,417 2,820,227
Other Electric Utilities 8,735,459 5,843,057
Other Operating Revenues
(Revenue Adjustments) 527,707 159,303
Total Operating Revenues $47,418,618 $43,822,125
Number of Customers (average)
Residential 27,074 26,855
Commercial and Industrial - Small 4,789 4,763
Commercial and Industrial - Large 17 17
Municipal Street Lighting 37 37
Area Lighting 1,238 1,323
Other Municipal and Other
Public Authorities 8 8
Other Electric Utilities 7 6
Total Customers 33,170 33,009
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 71,649 61,533
Hydro 100,158 149,323
Diesel 572 (758)
Purchases:
Nuclear Generated 215,006 331,988
Fossil Fuel Generated 327,016 175,648
Inadvertent Received (Delivered) (432) (74)
Total 713,969 717,660
Losses, Unaccounted for and Unbilled 43,377 42,076
Company Use 1,472 1,453
Electricity Sold 669,120 674,131
Sales:
Residential 173,580 173,799
Commercial and Industrial-Small 131,535 125,742
Commercial and Industrial-Large 133,405 150,881
Municipal Street Lighting 2,744 2,751
Area Lighting 1,626 1,740
Other Municipal and Other Public
Authorities 56,180 53,683
Other Electric Utilities 170,050 165,535
Total Sales 669,120 674,131
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 6,411 6,472
Revenue $589.06 $582.45
Revenue per Kilowatt-hour 9.19 cents 9.00 cents
(Chart)
Year-End Capitalization
(Percent)
1992 1993 1994 1995 1996
Total Debt 50.16 45.83 44.25 49.92 52.75
Common Equity 49.84 54.17 55.75 50.08 47.25
(Page 32)
Board
of
Directors
Maine Public Service
Company's eleven-member
Board of Directors is
composed of ten 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
Audit Committee
Budget and Finance Committee
PAUL R. CARIANI
President & Chief Executive Officer
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
David D. Daigle Farms, Inc.
Fort Kent, Maine & Orlando, Florida
Executive Compensation Committee
RICHARD G. DAIGLE
President & Chief Executive Officer
Cold Brook Energy, Inc., President
Daigle Oil Company
Fort Kent, Maine
Audit Committee
Executive Compensation Committee
J. GREGORY FREEMAN
President & Chief Executive Officer
Pepsi-Cola Bottling Company
of Aroostook, Inc.
Presque Isle, Maine
Budget and Finance Committee
Nominating Committee
DEBORAH L. GALLANT
President & CEO
Dix-Gallant Associates
Portland, Maine
Executive Compensation Committee
NATHAN L. GRASS
President
Grassland Equipment, Inc.
Presque Isle, Maine
Executive Compensation Committee
J. PAUL LEVESQUE
President & Chief Executive Officer
J. Paul Levesque & Sons, Inc.
(Lumber Mill) and
Antonio Levesque & Sons, Inc.
(Logging Operation)
Ashland, Maine
Pension Investment Committee
WALTER M. REED, JR.
President
Reed Farms, Inc.
Fort Fairfield, Maine
Pension Investment Committee
Budget and Finance Committee
(Back Inside Cover)
Transfer Agent
The Bank of New York
Shareholder Relations Dept. - 11E
P. O. Box 11258, Church Street Station
New York, NY 10286-1258
Tel. No. 1-800-524-4458
E-Mail: Shareowner-svcs@Email.bony.com
Stock Registrar
The Bank of New York
Annual Meeting
Tuesday, May 13, 1997
Form 10-K
The Company will provide shareholders
with copies of the Form 10-K upon request.
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@agate.net
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
Director and Officer Changes
Over the last year, several departments were combined and reorganized
into three lines of management, wholesale, retail, and administration, in
order to improve efficiencies and prepare for a future of change and
possible deregulation. Frederick C. Bustard, previously Vice President of
Engineering and Operations, was named Vice President of Power Supply and
Environment. He now directs the efforts of the Company's wholesale
operations. Engineering and operations functions, including retail sales,
are now led by Vice President of Customer Service Stephen A. Johnson.
Walter J. Elish, Director of Economic Development, was hired in
October, 1996 to step up efforts in spurring economic growth and
development in our service territory. Joining forces with community
economic development councils, Walt is coordinating various expositions,
trade fairs, direct mail, and other business recruitment functions to
attract development to the northern Maine region.
(Back Outside Cover)
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@agate.net
Exhibit 16
Deloitte & Touche LLP
125 Summer Street
Boston Massachusetts 02110-1617
Telephone: (617) 261-8000
Facsimile: (617) 261-8111
March 8, 1996
Securities and Exchange Commission
Mail Stop 9-5
450 5th Street N.W.
Washington, DC 20549
Dear Sir/Madame:
We have read and, except as indicated in the following sentence, agree
with the comments in Item 4 of Form 8-K of Maine Public Service Company
dated March 8, 1996. We have no basis to agree or disagree with the
statements made in (a) the second, third, fourth, fifth and sixth
sentences of the first paragraph, and (b) the fourth paragraph.
Yours truly,
/s/ Deloitte & Touche LLP
Deloitte Touche
Tohmatsu
International
Exhibit 99(n)
STATE OF MAINE Docket No. 95-052
PUBLIC UTILITIES COMMISSION June 26, 1996
MAINE PUBLIC SERVICE COMPANY ORDER
Proposed Increase in Rates
(Rate Design)
TABLE OF CONTENTS
I. SUMMARY OF DECISION . . . . . . . . . . . . . . . . . . . . . . . 4
II. INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . 4
A. Overview of the Case . . . . . . . . . . . . . . . . . . . 4
B. Background . . . . . . . . . . . . . . . . . . . . . . . . 6
C. Note on Precedent . . . . . . . . . . . . . . . . . . . . . 7
III. MARGINAL CUSTOMER COSTS . . . . . . . . . . . . . . . . . . . . . 9
A. Explanation of Marginal Cost and Rate Design Concepts . . . 9
B. Positions of the Parties . . . . . . . . . . . . . . . . . 11
1. MPS and McCain's . . . . . . . . . . . . . . . . . . 11
2. Public Advocate . . . . . . . . . . . . . . . . . . 12
3. Advocacy Staff . . . . . . . . . . . . . . . . . . . 12
C. Analysis . . . . . . . . . . . . . . . . . . . . . . . . . 13
1. MPS . . . . . . . . . . . . . . . . . . . . . . . . 14
2. OPA . . . . . . . . . . . . . . . . . . . . . . . . 14
3. Staff . . . . . . . . . . . . . . . . . . . . . . . 16
IV. MARGINAL TRANSMISSION AND DISTRIBUTION COSTS . . . . . . . . . . 18
A. Methodology: Reliability Index vs. Vintaged Plant . . . . 18
1. The Reliability Index Method . . . . . . . . . . . . 18
2. The Vintaged Plant Method . . . . . . . . . . . . . 18
B. Unit Costs . . . . . . . . . . . . . . . . . . . . . . . . 18
1. Marginal Unit Transmission Cost . . . . . . . . . . 18
2. Marginal Distribution Capacity Cost . . . . . . . . 19
a. Method . . . . . . . . . . . . . . . . . . . . 19
b. Positions of the Parties . . . . . . . . . . . 19
c. The MPS Response to Staff and OPA Criticism . 20
d. Transmission and Dist. O&M Marginal Costs . . 21
e. The Significance of Statistical Tests of the
Regression Equations . . . . . . . . . . . . . 21
C. Analysis . . . . . . . . . . . . . . . . . . . . . . . . . 22
D. Total Costs and Allocation . . . . . . . . . . . . . . . . 23
1. Distribution . . . . . . . . . . . . . . . . . . . . 23
a. Positions of the Parties . . . . . . . . . . . 24
b. Analysis . . . . . . . . . . . . . . . . . . . 26
c. Data Quality . . . . . . . . . . . . . . . . . 27
d. Invitation to File Updated Class NCP Data . . 29
2. Transmission . . . . . . . . . . . . . . . . . . . . 30
a. Analysis . . . . . . . . . . . . . . . . . . . 31
V. MARGINAL ENERGY COSTS . . . . . . . . . . . . . . . . . . . . . 32
Analysis . . . . . . . . . . . . . . . . . . . . . . . . . 33
VI. MARGINAL GENERATION CAPACITY COSTS . . . . . . . . . . . . . . . 34
Analysis . . . . . . . . . . . . . . . . . . . . . . . . . 36
VII. REVENUE RECONCILIATION . . . . . . . . . . . . . . . . . . . . . 37
A. EPMC and Other Reconciliation Methodologies . . . . . . . 37
B. OPA's Proposed Generation Allocator Method . . . . . . . . 38
C. Conclusion . . . . . . . . . . . . . . . . . . . . . . . . 40
VIII. RATE STABILITY AND RATE DESIGN DETERMINATION . . . . . . . 41
A. Rate Design Determination . . . . . . . . . . . . . . . . 41
B. Rate Design Policy Issues . . . . . . . . . . . . . . . . 43
IX. CONCLUSION . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
APPENDIX A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Procedural History . . . . . . . . . . . . . . . . . . . . . . . . . . 48
I. SUMMARY OF DECISION
In resolving this matter of rate design for the Maine Public Service
Company ("MPS" or "the Company"), we largely adopt the analysis and
recommendations developed by Advisory Staff but further modify the
Advisors' proposed rate design to comport with our judgment on fair
allocations to classes. In so doing, we find that the Advisory Staff has
identified marginal cost results that provide a reasonable starting point
for designing rates, but because of data, methodological, and rate
stability concerns, we will not order full implementation of the marginal
cost results. We find that conservative rate design changes are
reasonable due to data and methodological concerns and to avoid further
rate shock to customers who already face three further rate increases in
the next four years.
The class revenue requirements are shown on Exhibit 1 attached
hereto. The reader should note that the figures shown in Exhibit 1 are
stated relative to rate levels in December, 1995. Consequently, it is
necessary to subtract 4.4% increase already in effect for all classes as
of January 1, 1996 in order to arrive at the incremental increase or
decrease that will result for any class as a result of this Order.
Finally, recognizing that the distribution marginal cost results in
this case were made less reliable by outdated and mismatched non-
coincident peak (NCP) data, we invite the Company to present revised NCP
data for consideration in a limited proceeding for additional adjustments
to this rate design for implementation in February, 1998, if warranted at
that time. We would also consider rate design flexibility proposals at
that time, if proposed by any party.
II. INTRODUCTION
The Procedural History for this proceeding is contained in Appendix A
to this Report.
A. Overview of the Case
This case is both overdue and timely. Rate design review for
MPS is overdue, given the passage of time since its last rate design case
and the changes that have occurred within the Company's service territory
over the last 10 to 15 years. It is timely to do so now because of the
changes that are now occurring in the electric industry. This case and
the related rate plan establishing a multi-year revenue requirement will
set the starting point for MPS and its customers' participation in an
increasingly competitive electricity market.
This case contained a high degree of controversy over the
Company's presentation of its case in this proceeding. The Company has
acknowledged that it prepared its cost studies and rate design proposal
using data, methodology, and analysis from preparation for its last rate
design proceeding in 1987 (including class usage data from the early
1980s. The Company's proposals also did not reflect or address
significant, more recent precedent on rate design methodologies and
policies. /1
These facts diminished the value of this ratesetting exercise
and its results. Although the Company made several subsequent
modifications as the case progressed, incorporating portions of updated
data or methodologies as the Company was able to collect or analyze more
recent data available to it, in our view, certain infirmities, such as the
quality of the NCP data, have not been adequately redressed. /2 This
circumstance, unfortunately, has resulted in a proceeding that makes
difficult the confident delivery of a comprehensive redesign of rates and
contributes to our decision not to move further toward full EPMC results.
While we are cognizant of the Company's small size and minimal
staffing levels, the quality of a ratemaking decision depends greatly on
the quality of supporting evidence in a case, and all -- parties,
decisionmakers, and customers -- are impacted by this circumstance.
Nonetheless, while the determination of a reasonable and fair rate
design is never free from doubt, we are confident that our conclusions
have taken into account the uncertainties inherent in the evidence and
provide a reasonable basis for some modest rate design changes. The risk
of basing some changes on relatively poor data is no greater, perhaps,
than the continued risk of perpetuating a rate design based on even older
data and methodologies that this Commission no longer uses.
We do not wish to suggest that the Company has otherwise not
performed adequately. We recognize that errors will occur, particularly
when working under time pressures, and some compromises in data or
analysis may be necessary in certain circumstances. We recognize, too,
that ultimately many rate design decisions are a matter of analytic or
policy judgment about which experts and policy makers may disagree. All
of the witnesses in this case have given us the benefit of a full
understanding of the differences in how they have applied that judgment
and how they view the applicability of the evidence for the outcome of
this case. It is our task, then, to sort through the facts and argument
to determine how to establish just and reasonable rates for the Company
and to make our policies as clear as possible.
B. Background
MPS's last rate design case, Docket No. 87-009, set class
revenue requirements based on embedded cost studies but based intraclass
rate elements on marginal cost analysis. The case was resolved by a
stipulation in which MPS agreed to conduct further class load research
(some of which was used in this case). Subsequent revenue increases have
been applied across-the-board, in effect perpetuating a rate design based
on embedded cost principles.
In the intervening years between Docket No. 87-009 and this
case, the Commission fully adopted and developed its marginal cost
methodologies for electric rate design, primarily in Docket Nos. 89-068
and 92-315(I), both involving Central Maine Power Company. Prior to
Docket No. 89-068, marginal costs had only been used to establish rate
elements within rate classes. In Docket No. 89-68, marginal cost, rather
than embedded cost, was first used to allocate revenues to classes. This
change in rate design policy was based, in part, on the expectation that
marginal cost allocation would be easier and less complex to do, and the
belief that it would be a less arbitrary method of assigning costs to
classes than the embedded methodology which relied heavily upon judgments
about how to divide up responsibility for common costs. With marginal
cost methodology, unit cost figures could be calculated. /3
In Docket No. 92-315(I), the Commission set out to find the
general utility planning strategy that best comports with the public
interest, and to develop a set of general guidelines that can be used by
CMP in a subsequent case to translate that strategy and its underlying
costs into a specific rate design proposal. /4 The case was ultimately
stipulated by most of the participating parties. However, in its final
Order, the Commission delineated several cost and policy findings related
to the electric industry in general and to ratesetting in this
jurisdiction. Docket No. 92-315(I) was designed to be a precursor to
conducting a rate design case for CMP, /5 resolving foundational cost and
policy issues. Notably, in 92-315(I), while the Commission found
insufficient reason to approve CMP's proposed declining block rate, the
Commission did agree that there no longer appeared to be a basis for
requiring inclining block rates. The Commission also rejected CMP's
proposal for optional rate classes reaffirmed existing ratesetting
policies, further defined planning horizons for determining costs and
designing rates, and endorsed particular methodologies, including the
modified peaker method, for use in CMP's next marginal cost study.
C. Note on Precedent
There has been much discussion in this proceeding among the
parties regarding the appropriate methodologies for marginal cost rate
design for electric utilities. Both the Staff and the Company have
asserted that the methodologies they have used have been "approved" by the
Commission and, therefore, provide authoritative precedent. In general, a
stipulated result does not have (and is not intended to have) the same
precedential significance that a litigated resolution will have. That is
because stipulated results, more often than not, involve compromises by
the parties made to resolve issues that would otherwise consume much time
and resources in litigation, and as a hedge against the uncertainty of the
end result if left in the hands of the decisionmaker.
The ultimate significance of the parties' eagerness to claim the
authority of precedent can be distilled to the realization that, as a
general matter, regulatory policy is accretive, building upon prior
determinations. Prior approvals legitimize current and similar proposals
and help persuade the decisionmaker. Commissions will recognize and
employ current, established policies even as they work to form new ones
for the future. Consequently, as with all regulatory determinations,
while another utility may not be absolutely bound to apply methodologies
endorsed by the Commission in the most recent prior proceedings, insofar
as any utility proposes to depart from that precedent, it will bear the
burden to persuade the Commission that it is reasonable to do so.
In this context, it is useful to realize that Docket No. 92-
315(I) is not adequately described as a case resolved by stipulation of
the parties, for while some issues were resolved by stipulation, the
Commission explicitly issued an Order containing many findings and policy
determinations of its own on several issues of fundamental importance to
guide future electric rate design. Consequently, the case did provide
important regulatory policy statements and precedent on those issues.
III. MARGINAL CUSTOMER COSTS
A. Explanation of Marginal Cost and Rate Design Concepts
To promote clarity in what may be a complex and confusing
discussion, we begin with a discussion of the concepts involved in
marginal cost economic theory as well as their applicability to rate
design and the specific cost elements therein.
In economics, marginal cost is defined in terms of the total
cost concept. The total cost curve gives the sum of all costs incurred to
produce a given level of output. Total costs include fixed costs (e.g.,
for physical plant), which are incurred whether or not any output is
produced, and variable costs (e.g., labor and raw materials), which are
incurred as a result of production. Opportunity costs are not included in
total cost. Marginal cost is defined as the change in total cost
associated with an additional unit of output. Both the total and the
marginal-cost curves are defined over an entire output range, and the
marginal cost associated with a given unit of output does not depend on
whether or not the unit has actually been produced.
Rate design involves classifying and analyzing the various
components of electric utility total costs. Specific cost elements are
identified (e.g., transmission capacity, distribution capacity, generation
capacity, energy, and customer costs), and a per unit cost for each cost
element is determined. Once known, the cost elements can be used to
design rates that will collect total costs per year, based on the units of
each cost element (or "billing determinants") used by a rate class during
a year.
For customer costs - the costs associated specifically with
establishing and continuing service for a particular customer - there are
two general types of cost element. One represents the cost of physical
capital used to serve a customer (e.g. meters and service drops), usually
incurred on a one-time basis. The other represents ongoing expenses
incurred in billing and servicing an account. We will refer to these cost
elements as equipment customer costs and account customer costs
respectively.
Equipment customer costs are actually quite variable from one
customer installation to another, and there can even be disagreement on
whether certain costs (e.g., some poles and transformers) should be
classified as customer costs or as distribution capacity costs. In this
proceeding all parties agree that the appropriate proxy for equipment
customer costs is the purchase-plus-installation costs of a meter and
service drop. Let us assume that this total is $M. The meter cost, $M,
is a cost element per life of the meter, say 35 years. A meter cost per
year is an annualized level amount that will amortize $M over 35 years.
The meter cost per year can be thought of as similar to a mortgage
payment, or a rental fee, that will pay for the meter over its service
life. /6
There are two major approaches to establishing a dollar amount
for cost elements. The first is to use historical (or "embedded") costs
actually incurred. The second, more modern, is to use marginal costs,
i.e., the cost of the next unit. A straightforward and plausible
application of the historical approach to equipment customer costs would
be to find the average purchase-plus-installation cost of meter and
service drop of the utility, and then annualize that amount to determine
equipment customer cost per year. This average cost will be different
than the actual cost caused by specific customers for almost every
customer; few if any customers impose precisely the average cost on the
utility.
A straightforward and plausible application of the marginal cost
approach would be to use the purchase-plus-installation cost of a new
meter and service drop, annualized, to establish the marginal equipment
customer cost per year. /7 If all customers were charged this amount in
rates only the new customers would be paying the costs that they imposed.
Others would be paying more, or perhaps less, depending on the specifics
of the costs that they imposed in the past. If all customers were paying
a marginal equipment customer cost in rates, this charge could be thought
of as an equipment rental charge based on the current replacement cost of
their equipment.
Current rate design policy in Maine is to use marginal costs to
determine the dollar amount for rate elements. One rationale for this
involves giving the "right" price signal. The underlying theoretical
argument appeals to allocative efficiency: if some consumer is willing to
pay the costs of producing the next unit, then that unit will be supplied.
(Strictly speaking, this is the textbook argument for short term marginal
cost pricing. It would normally count against pricing at long term
costs.) Another rationale offered for the use of marginal costs involves
cost causation, because marginal cost pricing results in customers paying
the costs that they actually impose on the utility. This justification,
however, may be misleading, in that historical costs are the costs that
customers have caused, while marginal costs are the costs that will be
imposed by future expansion, which may be caused more by new customers
than by the increased use of existing customers.
An historical cost approach to rate design would generally set
rate elements equal to average historical costs for a cost element (per
year). When these rate elements are applied to billing determinants that
represent the unit use of each cost element, they will collect a total
amount that covers the utility's total historical costs (per year). A
marginal cost approach to rate design would set rate elements equal to
marginal costs. When marginal cost rate elements are applied to the same
set of billing determinants, the total amount collected, marginal cost
revenues, may be higher or lower than the utility's total costs (or
revenue requirement). This requires an adjustment to marginal cost rates,
the "reconciliation," in order to design rates that collect the correct
amount of total costs. In Maine we have used EPMC (equal percentage of
marginal costs) to perform the reconciliation, which simply marks up (or
down) all rate elements by the same percentage, so that the total
collected will equal the revenue requirement. This procedure preserves
marginal cost price ratios, but does not price at marginal cost. In this
proceeding, the resulting rates will be about twice the marginal costs.
B. Positions of the Parties
1. MPS and McCain's
MPS calculates marginal equipment customer costs using the
"straightforward" marginal cost method outlined in the preceding section.
According to the Company's calculation, totals for meter and service range
from about $250 per customer for the residential class to about $20,000
per customer for the H-T industrial class. The annual costs range from
about $27 per residential customer to about $2,100 for an H-T customer.
Totals for all account marginal customer costs range from about $51 per
customer per year for residential customer to about $2,200 for an H-T
customer. Total marginal customer costs (equipment costs plus account
costs per customer per year) range from about $78 for residential
customers to about $4,300 for H-T customers.
These totals are then used to calculate marginal customer
cost revenues, which are then added to all other types of marginal costs,
to obtain total marginal cost revenues for each class. Finally EPMC is
performed and the required percentage rate change for each rate class is
calculated. Marginal customer costs as a percentage of total marginal
costs are about 17% for the residential class and about 1% for the H-T
class. This reflects the difference in the number and size of customers
in these classes.
Intervenor McCain Foods (McCain's) supports the position of
MPS on marginal customer costs.
2. Public Advocate
The Office of the Public Advocate ("The Public Advocate" or
"OPA") calculates equipment customer costs using a variant of the
historical method outlined in Section A above: "Marginal customer
capacity cost should be based upon the total of embedded customer costs."
However, instead of using an average of historical costs of meters and
services, OPA uses a depreciated amount. OPA's witness Smith shows about
$26 for meter cost and $44 for account cost for residential customers.
MPS calculates about $68 and $178, respectively. The effect is similar
for other classes. OPA then uses the same 35-year annualization factor
that MPS uses (0.10740) to calculate the annualized amount. The result is
an annualized meter customer cost of $7.67, while MPS calculates $26.67
for this cost.
OPA's calculation of marginal account customer costs
differs from MPS's calculation largely in the expense for customer service
and information. After examining and revising MPS's data for this account
and making a number of revisions, OPA concludes on the basis of regression
analysis that there is no relationship between this type of expense and
the number of customers. OPA therefore places zero in all entries for
account customer costs thereby eliminating a very small expense item from
its calculation of total marginal customer costs.
OPA gives total marginal customer costs, per customer per
year, ranging from about $49.50 for residential customers to about $3,340
for H-T customers. This compares with MPS's $78 and $4300 for the
corresponding costs.
OPA offers a number of criticisms of MPS's approach to
marginal customer costs. First, existing customers do not impose the
annualized costs of a new meter on the utility. Second, marginal cost
price signals are not relevant for the decision to become a customer and
might be prohibitive if used. Third, using MPS's marginal customer costs
in combination with EPMC reconciliation will inappropriately allocate
other costs. Finally, MPS's procedure treats existing customers as if
they are new, as if all meters and services will "need to be replaced this
year and again next year and again the year after."
3. Advocacy Staff
Staff argues against applying marginal equipment costs for
new customers to existing customers, as MPS does, on the theory that
equipment for existing customers are sunk and, therefore, by definition
cannot be marginal. Staff argues instead that an appropriate conception
of marginal costs for existing customers would reflect the "ongoing
marginal capital costs" of continuing to serve a customer already on the
system. This ongoing marginal cost is the opportunity cost of having the
capital equipment in place. The equipment could be used to serve another
customer, as an alternative to purchasing and installing new equipment.
In practice only meters, and not service drops, are reused, so Staff
calculates the opportunity cost of an in-place meter. This calculation
takes into account such costs as removing and refurbishing the in-place
meter, subtracting these from the purchase cost of a new meter. This is
the value to the utility of an in-place meter that could be used as
alternative to a new meter. This opportunity cost is the ongoing marginal
capital customer cost of an existing customer.
Staff claims that this treatment of marginal costs for
existing equipment as the opportunity cost of having such equipment in use
is consistent with other marginal cost procedures used by this Commission.
For example, the marginal cost of generation capacity is measured using
the market value of that capacity, which is the opportunity cost of using
it to serve the utility's customers.
Staff calculates the market value (marginal cost) of
meters, and then combines them with account marginal costs to calculate
total marginal customer costs. These totals range from about $48 for
residential customers to about $2,400 for H-T customers. These figures
compare to $78 and $4,300 for MPS and $50 and $3,400 for OPA. Then total
marginal costs by rate class and the remainder of the EPMC reconciliation
are calculated.
Staff's treatment of account marginal costs differs from
that of MPS, which includes uncollectibles expense as a customer cost.
Based on a regression analysis showing a very low R2, MPS determined that
uncollectibles are not a marginal cost, and therefore omitted them from
the study. Staff argues that these costs are marginal, since they are
incurred at the margin and are largely related to the addition of
customers.
C. Analysis
The differences among the parties on customer cost issues are
largely conceptual. The parties agree that meters and service drops are
the appropriate proxy for equipment costs, and there is little
disagreement over the data. OPA disagrees with MPS on whether customer
information costs should be treated as marginal, and Staff disagrees with
MPS on whether uncollectibles costs are marginal.
1. MPS
As noted above, MPS has performed a straightforward and
conceptually orthodox calculation of marginal customer costs, using a
methodology that has been endorsed by the National Association of
Regulatory Utility Commissioners ("NARUC"). The resolution of this issue
will depend both on the strength of the alternative methods endorsed by
OPA and Staff and on our conclusions with respect to the ongoing validity
of applying standard marginal cost ratemaking principles to this cost
item.
2. OPA
As noted above, OPA employs a variant of the historical
cost method, using depreciated rather than original total meter and
service costs in rate base, and then analyzing this cost using a 35-year
factor. This is an inconsistent historical approach. It would have been
consistent to use total original costs and a 35-year factor, or to use
depreciated costs and an annualization factor based on average remaining
meter life. Mixing costs that have been depreciated for a number of years
with a full life annualization factor understates this cost. This is
comparable to telling the bank that your level mortgage payment should now
be cut in half, because you have paid off half the principal. In our
view, this is a serious flaw in the OPA's customer cost proposal.
Another difficulty is that this Commission has in a place a
marginal cost rate design policy. To consider an alternative treatment of
this cost item as OPA suggests, a justification for departing from
standard cost allocation methodology is necessary. We must assess the
strength of the reasons given by OPA for departing from this policy in the
case of customer costs.
First, OPA correctly points out that new customers do not
impose the annualized costs of a new meter on the utility. However,
existing customers do impose the annualized full costs of their meter when
it was new. If cost causation is the rationale underlying this OPA
argument, then its marginal cost amounts are too low, because they apply a
35-year annualization factor to an already depreciated cost. Furthermore,
and more importantly, it is not assumed in the MPS calculation that
existing customers imposed the annualized costs of a new meter. The costs
of the new meter are used because that is what is dictated by the marginal
cost methodology for this cost element. If there is a quarrel here it is
with the marginal cost rate design methodology, not with any assumption
about cost causation. Standard marginal cost methodology always, and in
principle, uses costs of the next unit for valuing cost elements. All
units are priced in relation to that cost, however dissimilar it may be
from historical or depreciated costs.
Second, OPA argues that a marginal cost price signal from
this cost element is not relevant to the customer's service decision, and
might be prohibitive if they were used. The annualized cost for meter and
service in MPS's study, however, is $26.67, only a little over $2 a month
- - and hardly prohibitive as a stand alone component of rates. It is also
not clear why a price signal should not influence the service decision.
Suppose the customer were deciding whether to install a new service for
his barn or to extend his existing service. A customer charge could be
the marginal cost consideration. Further, if marginal customer costs
became prohibitive to some, the Commission could take this into account,
weighing the benefits of mitigation measures against the value of economic
decision-making through accurate price signals.
Third, OPA argues that marginal customer costs will
inappropriately allocate other costs via the EPMC reconciliation. For
example, uneconomic generation costs responsible for the reconciliation
gap will be overallocated to customer classes that have a relatively
higher proportion of customer costs. /8 This effect, however, is
intrinsic to marginal cost methodology, even if it does clash with some
intuitive judgments about cost causation and fairness. While the
Commission is always free to consider whether there are modifications of
the marginal cost methodology that improve upon the current standard
methodology, we decline to depart from the established methodology in this
instance.
Fourth, the OPA argues that the method used by MPS treats
all customers as if they were new. On one interpretation this argument is
the same as the first, above. If, however, we focus on language about
treating all meters and services as if they will "need to be replaced
every year," we apparently discover a fundamental misconception. MPS's
treatment does not attempt to collect a full meter and service cost every
year for every customer. Rather it develops an annualized cost reflecting
a 35-year life so that the cost of the meter is collected over the life of
the meter.
On balance, none of the arguments offered by OPA persuade
us to depart from our use of marginal costs as the starting point for rate
design.
3. Staff
As explained above, Staff's position rests on their
conception of ongoing marginal costs for existing customers. Part of the
supporting argument involves the claim that meter costs for existing
customers are sunk and therefore cannot be the marginal costs for these
customers.
While Staff's discussion of opportunity cost as the proper
measure of marginal cost has conceptual appeal and academic support where
costs are genuinely "sunk," we do not agree that the opportunity cost
approach should be used here.
First, opportunity cost is not an ongoing cost in the sense
of an expenditure that the Company incurs to serve existing customers, nor
is it a component of the Company's total costs. It therefore cannot be
part of a change in total costs, and similarly it cannot be a marginal
cost in the usual sense. In reply to this criticism Staff could say that
the ongoing marginal cost for existing customers is a component of total
marginal costs. In this use, however, total marginal costs cannot be
defined independently of the specific marginal costs (such as marginal
meter customer costs) that are added to obtain the total. There is a
circularity in the definitions of total and marginal costs in Staff's
approach. The standard total cost concept can be independently defined,
and then used to define marginal cost (as explained in Section A, above).
Moreover, we do not agree that, for the purposes of
marginal cost analysis, the cost of meters represents a "sunk" cost. The
parties in this case agree that a net increase in customers is the proper
proxy for marginal class usage. In order to increase the membership in
the customer class by one, one new meter must be added - all existing
meters (including refurbished meters no longer used by departing customers
and returned to service for customers who replace those departing
customers) are in use. The cost of the new meter to serve the incremental
customer is no more "sunk," for marginal cost analysis, than the cost of a
new car sitting on the dealer's lot.
As a final observation, and an additional reason to decline
to adopt the opportunity cost approach with respect to equipment customer
costs, we note that Staff's marginal equipment customer cost is, in
effect, a salvage value to the utility of an in-place meter, an amount
that could be almost any percentage of new meter cost, or even zero,
depending on the particulars. If it were zero, then equipment customer
costs would be zero and would play no role in rate design. That result
is, in our view, unacceptable on its face.
Having rejected the OPA and Staff approaches, we are left
with MPS's more conventional marginal cost approach to customer costs, and
we will adopt it here.
On two remaining matters of detail we will adopt the MPS
proposal. The first is whether uncollectibles should be considered a
marginal customer cost. We accept MPS's regression analysis as reasonable
evidence that there is not a marginal cost relationship here.
Furthermore, we are unpersuaded by Staff's argument that these costs are
marginal because they are incurred at the margin and are largely related
to new customers. /9 On the remaining issue, whether customer information
costs are marginal, we believe it is reasonable to conclude that such
costs would increase with the number of customers. The OPA's regression
analysis or the assumptions used do not persuade us to change our
conclusion.
Consequently, we will adopt MPS's treatment of customer
costs in its entirety.
The degree of difference on customer cost issues among the
various experts involved in this proceeding gives us further reason why,
to the greatest extent possible, consistent with the protection of
ratepayers, the Commission should get out of the pricing business. Free
markets are better determinants of appropriate price levels. Where there
are market failures we will remain involved, but, in general, we favor
systems in which companies risking and customers spending their own money
set prices.
IV. MARGINAL TRANSMISSION AND DISTRIBUTION COSTS
A. Methodology: Reliability Index vs. Vintaged Plant
1. The Reliability Index Method
MPS has used a method originally referred to as the
"Functional Subtraction Method" in the NARUC Electric Utility Cost
Allocation Manual, /10 to separate growth-related additions from
reliability-related additions to plant. In this proceeding, the method
has been called the "Reliability Index Method."
The Reliability Index Method requires that individual work
orders be examined and classified as required for either load growth or
reliability. Cumulative growth-related additions in dollars are plotted
against actual loads in kilowatts over an 18-year period. A linear
relationship is determined by a least squares regression. The slope of
the resulting line is the unit cost. Both transmission and distribution
unit costs are determined in this way. The Reliability Index Method was
used by MPS in Docket No. 87-009.
2. The Vintaged Plant Method
The Staff objects to MPS's use of the Reliability Index
Method. The Staff has a strong preference for a method used by both CMP
and Staff in Docket No. 92-315 called the "Vintaged Plant Method." Staff
believes the process of separating growth-related from reliability-related
plant investment to be too "judgmental" and "arbitrary."
Instead of using data based on growth related investment,
the vintaged plant method uses data based on net additions to plant that
can be obtained directly from plant records. Unable to secure net
additions plant data from MPS, Staff consultants, Swan and Psacharopoulos
(S&P), modified the MPS Reliability Index Method to correct perceived
infirmities.
B. Unit Costs
1. Marginal Unit Transmission Cost
S&P show that the period over which the transmission data
is selected can have a significant impact on the slope of the regression
curve, $63.76 for 1977-1994, $32.14 for 1980-1994, and negative $66.71
for 1986-1994. A longer time period, such as the 65 years used by CMP,
should theoretically produce a more stable result. S&P elected to use
forecast peak loads rather than actual peak loads since actual load growth
has been highly variable, even negative in recent years.
Another problem of concern to S&P was the lumpiness of
transmission investment with large amounts in some years and virtually
nothing in others. S&P elected to smooth the investment by using a 3-year
moving average rather than single year investments.
In Docket No. 92-315, CMP excluded investments in the
345 kV "backbone" transmission system because they believed that those
investments should be considered to be part of generation capacity cost.
S&P believe that MPS improperly included "backbone" transmission costs.
However, since those costs could not be identified, no adjustment was
made.
The S&P adjustments produce a marginal unit transmission
cost of $35.73 per kW compared to MPS's $63.76 per kW in 1994$.
The Public Advocate accepts the MPS Marginal Transmission
Cost.
2. Marginal Distribution Capacity Cost
a. Method
MPS used the same Reliability Index Method for
marginal distribution capacity cost as for marginal transmission capacity
cost. Staff has the same disagreements here as with marginal transmission
cost. Both Staff and OPA have additional objections to the underlying
data and its application.
b. Positions of the Parties
Staff
S&P criticized MPS for using the 1986 index value of
0.44 to separate growth-related from reliability-related investments for
the years 1977 through 1985 when only total investment data was available.
Staff and OPA found the average index value of the years 1986 through 1994
of 0.68 would be more appropriate since it represents a much larger
population of individually analyzed work orders. Staff and OPA corrected
the data using the 0.68 index value. In rebuttal MPS accepted this
correction as being appropriate.
Public Advocate
In deposition testimony, Gerow described how MPS
"sampled" distribution investments by looking at accounts with large
amounts of spending. The Public Advocate's consultant, Lee Smith, asserts
that MPS provided no evidence that the sample was representative of the
accounts that were not analyzed.
Smith corrected a typographical error in the MPS
calculation for 1994 and applied the same data modification as Staff,
except that Smith did not change actual peak loads to forecast peaks.
c. The MPS Response to Staff and OPA Criticism
MPS questions the theoretical basis for the Vintaged
Plant Method. MPS states that the method is based on the assumption that
any change in the current value of total plant from one year to the next
must be due to growth-related investments. MPS believes that the value
could change due to upgrades in construction quality. MPS cites the fact
that Staff was unable to produce any evidence that the Vintage Plant
Method was recognized in any other jurisdiction or had been scrutinized by
the Commission in Docket No. 92-315 where it had been accepted by
stipulation of the parties.
MPS stands by its use of the Reliability Index Method
pointing out that the method is recognized by NERA in the Gray Book series
and is discussed in the NARUC Cost Allocation Manual.
MPS also disagrees with Staff's criticism of the
process used by MPS in analyzing work orders and separating reliability
from growth-related investments, citing the Deposition Testimony of Howard
where the process was discussed. MPS points out that the separation was
done by accountants under the supervision of and in close consultation
with knowledgeable engineers. MPS also asserts that to the extent there
may be errors of over or under estimating of reliability-related
investments, the errors would tend to be offsetting.
MPS believes that Staff's use of long-term forecast
loads as the independent variable in the regression equations is improper
because; (a) MPS uses annual budget forecasts as the basis for its
construction planning not long-term forecasts, (b) actual loads better
represent and are closer in timing to construction, and (c) Staff didn't
use the 1992 forecast for the years 1992-1994 which recognized the closing
of Loring AFB. The latter choice is a major reason why the Staff's
resulting unit costs are lower than MPS.
MPS accepts Staff's and OPA's correction of the use of
a 0.68 reliability index in place of 0.44 for estimating the separation of
reliability related investment from total investment for the years 1977-
1987, for which work orders were not available to be analyzed.
MPS believes the fact that Staff's marginal cost
result is below embedded cost is a further indication that Staff's result
is too low. MPS cites that fact that Aroostook County has a less dense
population than CMP's territory as justification of why the MPS marginal
distribution cost is higher than CMP's. Conversely, MPS cites the fact
that its transmission system is predominantly 69 kV compared to CMP's
system at 115 kV as justification for MPS's marginal transmission cost
being lower than CMP's.
d. Transmission and Distribution O&M Marginal Costs
Staff found that O&M regression equations had very
poor R2 results, 0.14 for transmission and 0.02 for distribution.
Expenditures seemed to be relatively constant from year-to-year, possibly
more a function of year-to-year budgeting than load changes. MPS believes
that there should be some amount of O&M that is load-related but admits
that the data does not produce a convincing relationship. Finally, Staff
recommended that the marginal O&M costs be set at zero, and MPS did not
object.
Since there is a poor regression R2 and the amounts
are probably small, (less than $2.00/kW), we agree with Staff that
marginal transmission and distribution O&M should be excluded from the
calculation.
e. The Significance of Statistical Tests of the
Regression Equations
We have examined the R2 calculations used to evaluate
the relationship between load and investment in the Company and Staff
analyses. We find that while Staff's adjustments to the data produced
better R2 values, our confidence in their results did not increase
correspondingly, because the use of forecasted load increases the
linearity of the independent variable thereby yielding a better
mathematical result. The procedure does nothing, however, to mitigate
flaws in the dependent variable that result from a fairly arbitrary
separation of growth- and reliability-related investment.
C. Analysis
Both transmission and distribution plant are constructed for a
variety of reasons, primarily either to accommodate load growth or to
improve reliability. It is thought that for purposes of determining the
cost of constructing an additional unit (marginal capacity cost) to serve
an increasing load, either for existing customers or new customers, only
that construction cost necessary to serve load growth should be used in
the calculation. The construction cost associated with reliability-
related improvements should be excluded.
In this proceeding, we are presented with two methods to produce
marginal transmission and distribution capacity costs. The methods are
similar in that they attempt to develop a relationship between
construction expenditures and load over a time period of many years. This
long term relationship is an attempt to solve the problem of wide swings
in short-term costs from project to project due to size and uniqueness
and varying leads and lags in timing with respect to load growth. Both
methods have shortcomings.
The Reliability Index Method requires a tedious analysis of the
records of individual work orders to classify them as either growth
related or reliability related. The results depend on many arbitrary and
likely inaccurate judgments about the purpose of each project. The
Staff's concerns about data reliability are justified but the relative
size of errors or potential error has not been shown.
The Vintaged Plant Method uses net plant cost as shown on the
utility's books without the need for arbitrary judgments about growth
versus reliability. However, the use of net plant requires the
theoretical assumption that retirements of undepreciated plant can be used
as a proxy for reliability-related plant since gross plant cost is reduced
by each in the same way. It should be much easier to develop net plant
cost data than data that has been purged of reliability-related costs.
However, no party produced vintaged net plant data in this proceeding.
Thus, we have no comparable results to consider.
There are differences among the parties over whether the costs
should be related to actual loads or forecast loads. There is a certain
theoretical charm to using actual loads since plant construction will
likely occur at a lesser or greater rate than forecast loads would dictate
if the forecasts are typically inaccurate. In the MPS situation, actual
load growth is far from uniform. It levels off and then declines in
recent years producing a relationship to construction cost that can hardly
be considered linear and amenable to least squares regression. On the
other hand, the Company's budget represents the Company's own best
judgment of the costs it will need to incur to accommodate growth, and for
that reason may also serve as an appropriate basis for our calculations.
While it is not obvious on this record which is the better methodological
approach, for purposes of this case, we will adopt the Advisors'
recommendation to use forecast loads in part because they result in a
better R2 value. Having so decided, we will also note that in Docket
No. 92-315, CMP found that a non-linear, logarithmic equation provided a
better fit for relating investment cost to load. It cannot be said for
certain that the relationship of construction cost to load growth is
linear regardless of whether loads are actual or forecast.
In addition, the record is not clear with regard to the
causation and timing of construction expenditures. Rather than being
directly related to load growth, the Company argued that construction
spending may be more a function of the utility's annual budget which is
tied to expectations of its earnings and cash flow. It is certain that
expenditures occur in a "lumpy" way over time. Staff's rolling 3-year
average is an appropriate way to smooth "lumpiness" and at the same time
show an improved fit of the regression equation.
Staff's improvements to the MPS marginal transmission cost study
effectively reduce the unit cost by 44%. Distribution unit cost is
reduced by 28%. The reductions are significant showing that different
approaches to the analysis can produce results that substantially impact
overall revenue allocations. With less-than-complete confidence in their
accuracy, we will accept Staff's resulting unit costs. Although
stipulated for use in Docket No. 92-315, we are not satisfied that we are
able to sufficiently examine the Vintaged Plant Method or its application
to this proceeding on this record. Thus, we are not prepared to endorse
the Vintaged Plant Method, over other methods, as a matter of general rate
design policy at this time.
D. Total Costs and Allocation
1. Distribution
Our findings with regard to the unit marginal costs for
distribution are set forth above. Calculating the total amount and
allocation of the distribution marginal costs to the individual rate
classes requires examination of a variety of issues. Each of the parties
has presented its calculations based on varying methodologies and data
interpretation and manipulation techniques. However, Staff and the
Company seem to agree on the key element of the method that should be used
in such calculation (i.e., 12 NCP), provided that reliable data are
available.
The calculation of total marginal distribution costs by
each party shows the relative significance of this category of costs. The
Company's total distribution costs represent 13.1% of its total marginal
costs, the Staff amount represents 10.0%, and the OPA's proposed
distribution total amount equals 12.7% of the total marginal costs
presented by his witness. In addition, the allocation of costs to the
individual rate classes shows wide variations among the parties. For
example, the Company assigns 55.3% of its total distribution costs to the
residential class, the Staff allocation to residential is 47.3% of total
distribution costs, and the OPA assigns 49.9% of total distribution
marginal costs to residential customers. Accordingly, we view this
category as having both a relative and an absolute significance in
arriving at our overall marginal costs result.
In addition, as discussed more fully below, this category
of costs brings into focus the serious concerns expressed by the Staff and
the OPA regarding the quality of the data presented by the Company. While
our decision in this case is based on the record before us, we also will
allow an opportunity for a limited look at updated data and for parties to
provide support for their proposed method of employing those data.
a. Positions of the Parties
The Company has proposed a calculation and an
assignment of total distribution marginal costs that is based on weighting
the 12 monthly Non-Coincident Peaks (NCP) for each class by the
proportional responsibility (PR) method. The Company's calculation
involves multiplying the PR-weighted 12 NCPs of each class by the
Company's calculated marginal cost per Kilowatt (KW). The PR weighting
method is a capacity-related cost allocation mechanism that uses system
load data to calculate a demand responsibility for each month, day or hour
to be used as the cost allocator in cost of service studies. MPS
calculates an on-peak and an off-peak responsibility for each month, then
sums these to get each month's total PR, which is then multiplied by the
monthly NCP to arrive at the weighted NCP. The unit costs are determined
and applied separately to the primary and secondary level distribution
customers based on their proportionate share of the monthly NCPs. The
individual class marginal costs are then summed to arrive at total company
marginal distribution costs.
The Company first made use of the PR-weighted 12 NCP
method in its Rebuttal filing. It asserts that this method assigns cost
responsibility among the time periods and among the classes in relation to
actual cost causation.
The Staff concurs that use of NCP data for assigning
distribution marginal cost responsibility is theoretically correct, but as
will be discussed below, Staff felt it could not rely on the NCP data that
MPS presented. However, Staff does not agree with the PR weighting
method, stating that it is a rather old procedure that was developed to
facilitate the allocation of embedded costs. The Staff's recommended
method looks at each class's maximum demand on the distribution system, no
matter when it occurs, but by using and weighting equally all 12 months,
it also considers seasonal cost causation factors.
All parties agree that distribution demand costs are
likely incurred to meet demand at times other than just at the annual
coincident peak, so that NCP data is preferable to CP for use in any
allocation scheme.
While the Staff endorses the use of 12 months of NCP
data to allocate marginal distribution cost responsibility among classes,
it finds the load data supplied by MPS to be of such poor quality as to
render it useless for assigning costs in this case. Staff asserts that
the fact that the Company has mixed data from several sources and from
different time periods gives results that are anomalous, inconsistent or
impossible by definition. Specifically, Staff points out that load data
for the residential class is taken from a 1979 study and combined with CP
data from a 1990 study. While this technique resulted in only one of the
months (July) actually showing a diversity factor of less than one (which
is by definition, an impossibility), Staff concludes that other months may
have similar errors embedded in their results which are less obvious.
Staff also asserts that the commercial class results suffer from similar
problems of staleness and lack of support. Further, the NCPs for the ES
and EP-T classes were developed not through use of monthly estimated
diversity factors, but by use of a 2-month average factor which may not be
representative of the whole year. The Company seems to agree that its
load data is less than perfect, but asserts that it has arrived at a
reasonable NCP approximation that is usable in designing rates.
The OPA's witness, Lee Smith, has used a single NCP
allocator to assign cost responsibility among the various classes. She
argues that the distribution system is sized to meet the maximum demand
placed upon it at any one time by each customer class, and that this cost
causative responsibility is best reflected by using the individual class
annual NCPs multiplied by the marginal distribution cost per KW. In her
view, usage other than at the time of class annual peak is largely
irrelevant. As with the Staff, Ms. Smith was troubled by the
inconsistencies and anomalies present in the load data supplied by MPS.
To arrive at the class NCPs used in her analysis, she made numerous
modifications to the Company's class results, in many cases relying on her
analytical experience with similarly situated companies to estimate a
value. The OPA asserts that the results presented by Ms. Smith are a
reasonable compromise between the Staff's and the Company's positions, and
would allow the Commission to apply the theoretically correct NCP
methodology with class NCPs that are reasonable approximations.
b. Analysis
We find the load data problem troubling. It appears
that the Company revised its CP results at the Rebuttal stage of the case
and did not present any NCP numbers until that point in the proceeding.
Those NCP results engendered a high degree of discomfort among the other
parties. The Company attempted to introduce very late in the case further
revised (1994) load research data. Those data were excluded from the
record because of their untimeliness. It would have been preferable for
the Company to have provided these data at a much earlier stage.
Certainly, MPS should have been aware, prior to filing this case, of the
Commission's preference for the use of NCP data in allocating distribution
marginal costs. A utility always has the right to seek to vary from a
Commission's expressed policy or preference, so long as it can support its
arguments on theoretical or factual grounds, but it should not simply
ignore prior Commission policy.
We agree with many of Ms. Smith assessments with
respect to the quality of the load data and commend her efforts to salvage
something from the NCP results put forth by the Company. We also agree
with the Staff that the class NCP data is sufficiently flawed as to make
it unreliable for establishing marginal cost-based rates. While Ms. Smith
skillfully employed her experience and judgment in developing alternative
data inputs, we are concerned that in several areas her results may not
yield reasonable approximations of the true values being sought.
To ensure that the current regulatory policy in this
jurisdiction is clear, we reconfirm our finding from Docket No. 92-315
that class NCP data is the proper measure to use in allocating marginal
distribution costs among customer classes. We are not able to make a
finding at this time as to whether the single NCP method, as asserted by
OPA witness Smith, is the appropriate allocator, or whether the 12 NCP
methodology advocated by Staff and MPS is more appropriate. We find some
merit in the assertions made by both Ms. Smith and the opposing viewpoint
of Staff witnesses Swan and Psacharopoulos on the issue. There is
considerable logic in Ms. Smith's assertion that the distribution system
is built to meet the highest class demand whenever that occurs. However,
we have no evidence that the annual NCP for each class provides a good
approximation of how individual circuits, which serve customers from
several classes, are used. The Staff's proposed weighting technique could
present a better measure of the overall use of the system. Their
recommendation may provide a way of accounting for the fact that
individual distribution circuits serve more than one class of customer,
each of whom may put different demands on the system at different times of
the year and whose combined demand may drive the level of investment in
distribution plant. The weighting by proportional responsibility, as
advocated by MPS, gives additional weight to the times of the year when
the system generating and transmission portions of the utility system are
most heavily utilized, but it may be that some parts of the distribution
system are most heavily stressed at other times. We believe that the
issue needs to be explored further, as the record before us does not
adequately address the issues involved. As a matter of overall policy we
are unable to make a conclusive finding based on the record before us on
whether it is more appropriate to use 1 NCP or 12 NCP.
To establish marginal distribution costs for this
docket, however, we will employ the Staff's proposed method of applying
equal monthly weighting to the calculation of each class's probable
contribution to each month's CP. As explained above, the use of CP's is
not our preferred method, but given the infirmities of the NCP data in the
record, we accept Staff's proposed method as the best available
alternative. In addition, this method has been employed in other rate
design cases when NCP data was not available to develop rates that were
implemented by the Commission. As discussed further below, it also
appears that the CP data does not suffer from the serious defects that are
present in the Company's NCP data. We will discuss later in this report
how the use of less-than-ideal data and methods affects our overall
decision.
c. Data Quality
Staff witnesses presented many criticisms of the data
presented by MPS in this case. We must examine those claims, as they have
a direct bearing on our ability to rely on the marginal cost results in
establishing class revenue responsibility. We have already discussed the
lack of reliability surrounding the Company's NCP results. However, in
the case of all the marginal demand cost areas (i.e., generation,
transmission and distribution) our findings have relied on the coincident
peak data supplied by the Company as modified by Staff's witnesses. The
Staff in its Direct testimony claimed that a large number of problems were
present in the Company's CP data. These problems generally can be
classified as inconsistencies or anomalies. At Rebuttal the Company
presented revised CP numbers that it was able to obtain through additional
load research and billing analysis. While the Staff did not express
complete confidence in the Company's revised CP numbers, its criticisms
were limited to several specific areas, as detailed in the Surrebuttal
testimony of Swan and Psacharopoulos. In fact, the witnesses presented
adjustments to the Company's results that appeared to correct the most
obvious of the problems, most of which can be characterized as errors in
computations.
The most significant problem area was the method by
which the Company scaled up its estimated class CPs to arrive at the known
(i.e., measured) system monthly peak. The Company employed an annual
scaling factor that it applied to all rate classes, while Dr. Swan used a
separate factor for each month that was applied only to those classes that
were not actually measured. As described more fully later in our
discussion of the generation capacity costs, we have found Dr. Swan's
modifications to be reasonable and appropriate. They are based on sound
logic, and MPS did not dispute their validity.
As discussed in Section IV. C. above, the Staff also
raised significant concerns about data quality and reliability in the
calculation of unit costs for transmission and distribution. While we
agree with Staff's concern about the calculation of the unit marginal
costs for distribution and transmission plant, we must look at how these
results are applied in the final analysis. In the case of transmission
plant, a single unit cost is calculated for all customers that use the
transmission system, i.e. every customer class. A second calculation is
done for customers who take service at less than transmission voltage
(everyone except the H-T class), and the results of the two calculations
are added together to arrive at total marginal transmission costs. The
important point is that, except for the slightly lower rate charged only
to the transmission voltage level customers, all customer classes receive
the same unit cost, and changes to the unit cost will affect all customer
classes in a relatively (but not exactly) equivalent manner.
A similar marginal cost calculation occurs with
distribution costs. Here the distinction is between secondary and primary
voltage level customers. The classes that do not use the distribution
system at all (H-T and S-T) receive no distribution cost. The remaining
classes are allocated an amount based on the cost of the primary
distribution facilities, and those that take power at the secondary level
(the same as primary except the ES and EP classes are excluded) are
charged an additional increment based on the cost of the secondary system.
When unit distribution costs are recalculated, all categories of classes
change to the new rate. Assuming no change in allocation, the change in
distribution costs would be proportionately equal for all classes. In
addition, the ratio of distribution to total marginal costs affects the
overall result, and the EPMC reconciliation magnifies any difference.
We have conducted relatively simple sensitivity
analyses to determine the parameters that encompass the possible changes
in marginal distribution costs. Transmission costs were not so analyzed
because they are relatively small. We examined the results of three
scenarios, all used in conjunction with Staff's allocation percentages: 1)
cutting MPS's estimated unit distribution cost in half; 2) doubling MPS's
estimate, and 3) using MPS's unit costs with the Staff allocations. Using
MPS's unit cost with the Staff allocation has the least effect on the
required increase as calculated with the EPMC reconciliation, although the
spread between the largest increase and largest decrease widens. Reducing
MPS's estimated distribution cost by one-half reduces the spread, while
doubling the estimate widens the spread. The absolute numbers, while
showing large variations in the required revenue adjustment, are not as
crucial as the fact that the positions of each class do not change in
relation to one another. Hence, we conclude that a carefully designed
rate stability adjustment could be effective in overcoming these data
concerns. While we agree with the Staff that the data underlying the unit
cost calculations exhibit serious problems, we find that those problems
are not fatal but can be considered and accommodated through the rate
stability adjustment that we have proposed.
Accordingly, we conclude that the data quality
problems are not as extensive as Staff claims, and can, to a large degree,
be addressed by avoiding the use of the most seriously flawed data and by
not blindly implementing the final marginal cost results. Consequently,
we have not used the data which presents the major problems, the class
NCPs, in arriving at marginal costs. While the CP information is not
completely reliable, is a reasonable starting point in establishing rates
based in part on marginal costs. We must use the cost results with
caution, but we do not find that the CP data is so bad as to render it
unusable. Nor do we find, in light of past rate design cases before this
Commission, that substituting use of an equally weighted CP in place of a
more preferable NCP factor in calculating class marginal distribution
costs leads to unacceptable results. Rather than reject the results of
all of the marginal cost calculation, we will take the data shortcomings
into account in reaching our final conclusion.
We will use Staff's results as the proper calculation
of total marginal distribution costs, as well as of the allocation of
those costs among customer classes.
d. Invitation to File Updated Class NCP Data
To address the NCP data quality problem, we will allow
MPS the opportunity to file updated class NCP data, as well as its
proposed method of using NCP's as the basis for allocating distribution
marginal costs. Should MPS choose to make this filing, our intention is
that this limited proceeding will be completed in time to be implemented
with the Company's rate change currently scheduled for February, 1998.
The only issues to be considered are the class NCP data itself, the use of
one annual NCP versus 12 monthly NCP's as the proper allocator, and if the
12 NCP allocator is used, the proper method for weighting each of the
monthly numbers. We encourage the Company to work with the Staff, and
other interested parties in developing the methodology to be used in the
study and in resolving as many disputes as possible prior to making its
filing.
2. Transmission
Having decided how to set the marginal cost of transmission
in Section IV.C. above, we now allocate those costs to the individual rate
classes. Here the differences among the parties' positions are not great,
but they do reflect some conceptual variations that may indicate
fundamental differences, or even misunderstandings, about the allocation
process. While the absolute dollar differences among the parties is not a
major driver of the total marginal cost calculation, the large
reconciliation from marginal to embedded costs serves to magnify in the
final results the relatively small transmission cost differences. In the
Company's calculation, transmission represents about 2.5% of total
marginal costs, while the Staff proposal regarding transmission costs
equates to about 1.6% of the total. While the OPA witness used a
calculation that is fairly close to the Company's number, in his Brief the
OPA supports the Company's calculation.
Both the Company and the Staff assign marginal transmission
costs to each of the rate classes by use of 12 CP weighted by Probability
of Peak (POP) methodology, which is the same method each used in
allocating their generation capacity costs. In fact, each uses the same
CP numbers for each calculation.
MPS does not determine a total-company marginal
transmission cost by multiplying the actual annual CP by the marginal unit
cost. Rather, it multiplies the weighted loss-adjusted CP for each class
by its determination of the marginal cost for that class and then sums up
the class amounts to get its total company cost. The H-T class receives
slightly lower per unit cost, since it does not make use of the
subtransmission system as all other classes do.
Before allocating costs to each class, the Staff determines
the total-company marginal cost by multiplying the annual actual CP by the
unit transmission marginal cost applicable to the transmission and
secondary/sub-transmission portions of the system. Staff then allocates
this total to the individual classes by use of the ratio of each class's
contribution to the monthly peak multiplied by each month's probability of
it being the annual peak. The Staff also assigns no subtransmission cost
to the H-T class, and performs its transmission and subtransmission
allocations in a two-step process, which accomplishes essentially the same
result that the Company shows in a single step. The key difference is
that the Staff allocates the total cost derived by use of the annual CP,
while the Company sums the costs that it calculates for each class, based
on the POP-weighted CPs to arrive at a total cost. Staff also employed
class CP numbers that were adjusted by Dr. Swan to account for
inconsistencies and anomalies.
a. Analysis
We find that Staff has applied the marginal cost
theory correctly by first determining total costs, and then allocating
those costs to the individual classes. The Company's method and
subsequent result are inconsistent with the proper application of marginal
cost theory. While it is also not clear if the Company's miscalculation
is simply a result of mathematical errors or a misunderstanding of the
marginal cost theories employed by the Commission, we expect the Company
to correct this in any future rate design filings. In this case, we
accept the Staff's allocation methodology and allocation factors using the
CP numbers as adjusted by Dr. Swan.
V. MARGINAL ENERGY COSTS
Marginal energy costs are designed to measure the Company's cost of
supplying an extra kilowatt hour (Kwh) of power to its various customer
classes during each of its four seasonal and daily time periods. It is
measured by running the Company's production costing model through
successive iterations assuming small increments in additional energy use
over an intermediate term (5 years in this case) and applying the average
seasonal and diurnal per Kwh results to the test year energy billing
units. There is essentially no dispute between the Company and the other
parties regarding this methodology, because Company witness Gerow asserts
that he has accepted the modifications proposed by the Staff witnesses.
The actual cost of energy on a per Kwh basis used in the calculation
varies slightly between Staff and Company, but the difference represents
only about .25% of the total marginal costs, a very small difference,
inconsequential to the overall result. As discussed below, the OPA has
proposed a slightly different per Kwh cost result, based on the
recommendations of its witness, Ms. Smith. The OPA's marginal energy
costs are approximately 9% higher than those of the Company and the Staff.
In its Reply Brief Staff mentions the issue of variable O&M costs,
which MPS claims the Staff failed to include in its marginal energy costs,
as well as having excluded them from its marginal generation costs. As
explained below in our discussion of marginal generation capacity costs,
we have found that Staff was correct in excluding variable O&M from the
calculation of marginal capacity costs. In the case of marginal energy
costs, Staff responds that it merely used information supplied by the
Company in computing the forward-looking marginal energy costs. It
accepted the Company's determination of what generating unit or power
purchase was on the margin at any point in time over the 1996 to 2000 time
period. Most of the Company's additional energy is supplied from power
purchases, and there would be no variable O&M associated with this energy.
The OPA witness agrees with the methodology used by the Company, but
she asserts that several changes should be made to the Company's energy
resource plans in order to more accurately reflect how MPS should be
running its system. The adjustments made by OPA witness Smith are: 1) a
price of $15.00/Mwh is imputed for Maine Yankee off-system sales, based on
other sales prices obtained by utilities in New England; 2) a further
increase in the sale price for Maine Yankee above the inflation estimate
is added to the Company's numbers; and 3) a reduction in Maine Yankee's
capacity rating is recognized over the remaining life of the plant due to
the recently completed generator tube resleeving operation. The OPA
questions the Company's conduct of its off-system sales practice, because
the Company typically sells a portion of its Maine Yankee entitlement
while at the same time purchasing replacement power from New Brunswick,
thus lowering the net amount received by the Company. The OPA suggests
that such transactions should not be happening to the degree they appear
to be, since the overall result of these sales is to reduce MPS net sales
revenues relative to the market price of Maine Yankee entitlement.
Both the Company and the Staff respond to the Maine Yankee sales
price assertions made by the OPA witness. Staff asserts that its estimate
of $10.98 is based on actual 1994 sales results and is a good indicator of
actual future prices. Staff does not take issue with the manner in which
such transactions have occurred previously, or make any statement opposing
future transactions of this type. Further, Staff asserts that any de-
rating of Maine Yankee capacity is quite uncertain over the 5-year time
horizon being examined.
The Company defends its past sales/repurchase transactions as
effective in lowering its overall energy costs. It states that it is
selling small quantities of surplus power from Maine Yankee for relatively
short time periods, while the OPA witness is comparing those with longer-
duration sales commitments made by other utilities. Additionally, MPS
states that while it sells its Maine Yankee entitlement for relatively
short-time periods, it may have to purchase even smaller amounts of power
from New Brunswick to meet peak demands on it system.
Analysis
We find that the marginal energy costs presented by the Company
and Staff are most appropriate for use in establishing the Company's rate
design, based on the 5-year forward looking production cost methodology
employed. We reject the OPA's assertions with regard to Maine Yankee de-
rating as being too speculative at present. In addition, we cannot find
on the basis of this record that the OPA's assertions concerning the price
and conduct of Maine Yankee off-system sales are accurate.
A slight difference exists between the Company's and the Staff's
presentation of the actual marginal energy costs. The difference is
apparently caused by the manner and inputs used in running the production
cost model. In addition, the Company presented no evidence that any
variable O&M cost has been left out of the calculation. For our purposes,
we will use the numbers supplied by Staff.
VI. MARGINAL GENERATION CAPACITY COSTS
Marginal generation capacity costs refer to the costs that a utility
incurs in order to supply an additional amount (usually measured in
megawatts, MW) of generating capacity to meet an increased load. Although
not the case at the beginning of the proceeding, the parties now generally
agree on the basic methodology to be used in calculating the unit marginal
cost and the allocation of those costs to the individual rate classes.
However, several disputes remain concerning the correct numbers to be used
in the calculations.
The cost is calculated by determining the type of peaking generating
unit that would be used to meet the additional load and associated reserve
requirement, based on the utility's least cost resource plan. When the
utility's resource plan shows a short-term excess of capacity, the cost of
the peaker is discounted from the year of anticipated need to the year for
which rates are being set. When the resource plan indicates no such
excess, no discounting is necessary. To determine a utility's total
marginal cost of generation, the per KW annual carrying cost of the peaker
unit is determined and then multiplied by the utility's coincident peak
load. The total marginal cost is allocated to the individual rate classes
by looking at each class's monthly coincident peak load as a percentage of
the system's monthly CP, and then weighting each month's results by the
associated probability of peak. The calculation must, by definition, sum
to 1.00, or 100% of the utility's peak generation capacity cost. In the
instant case the parties agree that the appropriate unit to use as the
assumed peaking unit is the combustion turbine, the same proxy unit used
in several prior Commission rate design proceedings.
Although it originally advocated a method of class allocation that
combined the cost of a short-term probabilistic purchase with a discounted
peaker method, at the rebuttal stage the Company altered its position and
accepted the discounted peaker method as proposed by the Staff. However,
MPS asserted that the year of need is 1997, and it included in the annual
carrying cost calculation an amount that was designed to account for the
variable O&M associated with running the peaking plant. Although it did
not originally do so, at rebuttal the Company allocated the cost
responsibility to the classes by use of the 12 coincident peak (12 CP)
methodology. This method was put forth by Staff in its Direct case, and
has been accepted by this Commission in prior rate design proceedings.
MPS arrives at a marginal generation capacity cost of $90.03/KW based on
1997 as the year of need. The Company claims that Staff erred in
excluding variable O&M from both its capacity and its energy calculations.
Staff calculates the marginal generation capacity cost to be
$85.18/KW, based on 1996 as the year of need and no variable O&M included
in the amount. Staff states that only a half year of discounting for 1996
might be appropriate, because new rates from this proceeding will not
become effective until the middle of the year. The Staff assigns cost
responsibilities to the various classes by use of the probability of peak
(POP) weighted 12 CP method, although its allocation varies from that of
MPS because of several corrections made by Staff witnesses Swan and
Psacharopoulos to the CP data supplied by the Company due to discrepancies
or anomalies in the Company's method of calculating CP's for each of the
classes. In essence, the Company's method scales up all classes' POP
weighted monthly CPs to agree with the measured system CP by use of an
annual scaling factor. The Staff method scales up only those classes that
have unmeasured CPs, and the scaling is accomplished by use of a month-by-
month factor. The Company did not respond to the Staff's corrections,
either in its witness's rebuttal filing or in its Brief or Reply Brief.
Nevertheless, the Company continued to use the class allocations proposed
in the Rebuttal Testimony of Mr. Gerow.
Staff further asserts that the methodology employed by MPS in
allocating costs to the individual classes fails to arrive at the correct
total marginal generation cost, because the Company does not multiply the
individual class annual allocated responsibility by the annual system
peak, but only sums the individual months' allocations, which, as
described above, differ from those calculated by the Staff. By failing to
multiply the class responsibilities by the system peak, the Company's
calculation arrives at a cost that is something less than the system peak.
Staff further assert that no variable O&M should be included in the
calculation, because the purpose of the exercise is to determine the
marginal capacity cost of the peaking unit that is on the margin, not the
costs of actually supplying energy from that unit. Staff's calculation
does include an amount, albeit relatively small, to account for the fixed
O&M costs associated with the marginal peaking unit. Staff assert that
any variable O&M for energy supplied should be included in the marginal
energy cost, and we have addressed that concern in our discussion about
marginal energy.
The witness for the OPA, Lee Smith, presented a calculation of
marginal generation capacity costs that was based on a year of need of
2000, and that included variable O&M costs, as proposed by MPS. The
resulting amount, which was used in arriving at the rate design changes
recommended by Ms. Smith in her Exhibit 20 (part of OPA # 31), was
$77.28/KW. This unit cost was applied to the Company's single CP numbers
for each class. However, the OPA states in his Brief that he accepts the
Company's marginal generation costs for the purpose of setting rates in
this case.
Analysis
Based on the evidence before us and on Commission precedent, we
find, with one minor exception, that Staff's recommendations regarding
marginal generation capacity costs should be adopted in their entirety.
In accord with our findings in Docket No. 92-315, we affirm that the
discounted peaker methodology provides the best estimate of the
intermediate term marginal cost of generation capacity. The minor
exception to the Staff's calculation is that we find that 1997 should be
considered the year of need for the purposes of applying the discounting
technique to the capital cost of the peaker unit, because the rate design
that derives from this proceeding will not go into effect until mid-way
through 1996, and because the Company's resource plan shows 1996 to be
have a small excess, so no need actually exists until 1997. Although
new rates are to become effective in mid-1996, we will not use an
additional half-year of discounting, as suggested by Staff. This will
simplify the calculation, and it would result in only a de minimis change
to the overall marginal cost result.
We further find that variable O&M is not properly included in
the capacity cost of the peaker unit, because as Staff correctly points
out, the calculation is designed to measure only the capacity costs, not
the operating costs, of the peaking unit. We further find that generation
capacity costs should be allocated to each class based on the monthly CPs
weighted by their probability of peak, as presented by Staff. As with
other data areas in this case, the Company should refine its load research
techniques, so that in future cases there can be a higher degree of
confidence in the monthly CP numbers.
In summary, we find that the total marginal cost of generation
capacity and the allocations to each class as proposed by Staff should be
used in determining the Company's total marginal costs.
VII. REVENUE RECONCILIATION
A. EPMC and Other Reconciliation Methodologies
When rates are to be based on marginal costs, it is usually
necessary to reconcile the amount of revenue that the marginal costs would
yield when applied to the test year billing units to the total revenues
that the utility is allowed to collect, as determined through a revenue
requirement proceeding. Since a company's revenue requirement usually is
calculated on the basis of its booked accounting costs, this amount is
generally referred to as its embedded revenue requirement, and so the
reconciliation is characterized as marginal cost to embedded cost. The
size of this reconciliation varies from company to company, depending on
the relationship between the utility's embedded costs and its marginal
costs.
In this proceeding the amount of reconciliation is quite large,
no matter which party's estimate of marginal costs is employed. Based on
MPS's calculation, the mark-up from total marginal to total embedded costs
is 77.1%; the Staff's estimate of marginal requires a 98.9% add-on, and
the OPA marginal cost recommendation requires a mark-up of 87.0%. As is
discussed below, when the reconciliation is of the magnitude needed here,
the validity of the marginal cost based price signal is seriously
jeopardized. In fact, under such circumstance the validity of the use of
marginal costs to set rates may be called into question. Nevertheless,
our decision is based on the continued use of marginal costs as the
starting point from which rates are established. However, we invite
comments in future proceedings on alternative methods of setting rates
where the reconciliation is so large.
The total company marginal costs, as calculated using the
Examiner's recommendation for each category, are $25,932,941, which
requires a reconciliation amount of $24,251,174, or 93.5%. See Exhibit 2.
The parties have presented two recommendations for determining the amount
of reconciliation that is applied to each rate class. One, supported by
the Company and the Staff, is the equal percentage of marginal cost (EPMC)
method, in which each rate class receives the same percentage of the
reconciliation amount as is equal to the class's contribution to total
marginal costs. This method has been employed by the Commission in recent
rate design proceedings where marginal costs were used as the basis upon
which inter-class revenue allocations were determined. The OPA has
proposed a novel approach which it refers to as the generation capacity
allocator. This method allocates the required reconciliation amount by
each class's proportional share of the total marginal generation and
energy costs. The theory behind this proposed method is that the
difference between the total marginal and embedded costs is caused by the
Company's uneconomic generation (including energy) cost commitments, and
this proposed allocator allegedly assigns the responsibility for the
revenue difference to each class more fairly than the EPMC method.
The EPMC reconciliation method has been used previously because
it is relatively simple to apply and assigns cost responsibility
equitably; determining actual cost causation responsibility is a
difficult, complex and time-consuming process that would expend large
amounts of resources. However, the use of EPMC is questionable when the
amount of reconciliation is as large as it is in the instant case.
Clearly, the price signal that is supposedly sent by basing prices on
marginal costs is considerably dampened, if not totally nullified, with a
large reconciliation factor. However, some method of reconciliation is
required, and the EPMC method has several attributes that make its use
desirable. Among those are simplicity, equity and understandability by
customers. In prior cases the Commission has considered other methods to
accomplish the reconciliation. Among those are Ramsey pricing and
embedded cost studies. However, both are fraught with problems of their
own and, for varying reasons, have not been used to assign cost
responsibility.
Ramsey pricing assigns the reconciliation amount on the basis of
inverse elasticity of demand, that is, the customer classes that are found
to be the least elastic would receive the largest reconciliation amount,
since they are the least likely to alter their usage based on the price of
the product. While this method has a basis in economic theory, it is
difficult to apply in practice, mainly because reliable measures of
relative class elasticities are not available, and because it is often
viewed as being less than equitable. Since no party proposed its use
here, we will not consider it further.
Use of embedded cost studies, which were relied on by this
Commission prior to the change to marginal cost based pricing, require a
complete examination of the utility's investments and operating costs in
order to assign cost responsibility. The studies are generally complex
undertakings that require a method of assigning the joint and common costs
that are present to the various classes. Here again, assignment can be
difficult and contentious, and since there may be no "right" answer, the
ultimate allocation tends to be arbitrary and the level of such costs can
be quite large. No party has proposed use of an embedded study in this
docket, and the required information is not in the record.
B. OPA's Proposed Generation Allocator Method
The Public Advocate has proposed a novel reconciliation
methodology, in which the reconciliation amount would be allocated to
rate classes on the basis of a generation allocator which takes into
account both the capacity and energy requirements of each rate class.
OPA's support for this proposal rests on the claim that the
revenue deficiency (i.e. the reconciliation amount) is the result of
uneconomic generation assets and energy purchase commitments, and revenue
responsibility should be allocated on this basis to reflect the cause of
the deficiency. OPA also argues that when the reconciliation gap is so
large, EPMC will inappropriately allocate revenue responsibility.
MPS responds to the OPA reconciliation proposal with several
arguments. First, MPS argues, the proposal amounts to "reverse Ramsey"
pricing, allocating more revenue responsibility to the more elastic
customers, those with alternatives. This will drive them off the system
and result in higher rates for remaining customers. Second, MPS argues
that the OPA's claim that the reconciliation gap is due to uneconomic
generation-related costs has not been adequately supported. The Company
purports to show that where the revenue deficiency is broken down by
function, the resulting reconciliation is closer to EPMC than to the OPA
proposal.
As explained above, the policy of this Commission has been to
use an EPMC (equal percentage of marginal costs) reconciliation to bring
marginal costs revenues into equality with the utility's revenue
requirement. We are willing to consider a departure from this precedent
but will need substantial record basis for doing so.
We believe that if OPA's proposal produced pricing with the
actual perverse effects claimed by MPS, it would be bad policy. When we
look at OPA's recommendation, however, the recommended change to the
residential class is a small decrease (about 2%); the change to the
commercial class is a small increase about 1.4%); and the change to the
industrial class is a small decrease (about 2%). This is not what would
be expected from "reverse Ramsey" pricing and could be found to be an
acceptable result if otherwise justified.
We find MPS's second argument, an attempt to account for the
reconciliation gap in a precise manner, to be interesting. A number of
assumptions in the Exhibit are not explained, however, and their basis is
not clear (e.g. the claim that no excess costs are due to energy and how
MPS's contract with Wheelabrator-Sherman is taken into account).
Therefore, we cannot accept its conclusions at this time. On the other
hand, we would like to see OPA's assertion about uneconomic costs put to
the test, and MPS does so in a fashion that at least raises plausible
doubts. We cannot find in favor of either party on this issue at this
time.
OPA's reconciliation method is a hybrid of marginal cost and
historical cost allocation methods. This is a novel concept and no party
has analyzed its pros and cons in sufficient detail to allow for a
confident finding either way by this Commission. Therefore, we find that
this record provides insufficient evidence to persuade us to depart from
precedent. For now we will continue our policy of using EPMC.
C. Conclusion
While we recognize that use of the EPMC methodology in a case
where there is a large reconciliation amount may present problems, we find
that its positive attributes make it reasonable as a reconciliation
method. We will use it here calculate total revenue responsibility for
each class, based on the marginal costs determined above. This does not
mean that the actual rates will be set on this result, but it is the
starting point for our ultimate pricing decision.
We are not prepared to fully reaffirm EPMC as requested by
Staff. In principle, we would prefer to allocate reconciliation-gap costs
in a way that maximizes social welfare, recognizing the need for perceived
as well as actual fairness. We will leave open for the future our ability
to explore alternative methods at reconciliation, including increased
flexibility for the Company, as discussed in VIII.B. below.
VIII. RATE STABILITY AND RATE DESIGN DETERMINATION
A. Rate Design Determination
Having determined that class revenue responsibility should be
based on marginal costs plus an EPMC reconciliation, we next decide how
actual prices should be set. The major factors that will impact our
decision are the reliability of the data used in calculating the class
revenue requirements and our concerns with rate stability and fairness to
each class.
The area of data quality and reliability has been thoroughly
discussed in the sections where we determined the marginal costs for each
class by each category of cost. We found that the data was not completely
reliable, but was not so bad as to be useless. In making our final class
rate determinations, we will temper the results of the revenue requirement
calculation to account for the infirmities present in the data. This
tempering must reflect our judgment regarding the magnitude of the data
problems.
We also consider rate stability in order to avoid "rate shock"
to customers. Here we take into account how large an increase each
particular class can and should absorb, and what the various classes
should expect from a proceeding of this type. The OPA asks us to consider
that the service territory of MPS is among the poorest in the State and
that the customers of MPS will be required to absorb additional rate
increases over the next few years, based on the Stipulation approved by
the Commission in the revenue requirement phase of the instant proceeding.
The OPA urges that the Commission consider the ability of customers to pay
for these rather large increases.
We share the concerns set forth in the OPA's Brief. However,
even the OPA's own recommendations would require that one class of
customers (sub-transmission) receive an increase of more than 20%,
another class (ES) a 9.1% increase, while two other classes (Municipal and
street lighting) would receive decreases greater than 20% each. Such a
result does not contribute to overall rate stability.
Every class could put forth arguments as to why it should not
receive much of an increase or, alternatively, that it deserves a decrease
in its rates. We must balance the somewhat often inconsistent goals of
rate stability and cost causation in a manner that is reasonable and
equitable to all customer classes, while at the same time affording the
Company the opportunity to earn its revenue requirement.
Rather than accept the recommendation of the OPA, we will follow
the Staff's recommendation that because of the data infirmities, any
percentage increase should be conservative. Staff recommends increases
that are relatively equal for each class, with the transmission and
lighting classes receiving slightly lower increases. However, we have
found that the data problems are not fatal to our marginal cost results,
and while we are recommending relatively small changes, we find that the
results of the EPMC-reconciled marginal cost analysis may reasonably be
reflected to a greater extent than Staff has done.
Our rate design determinations are based on a comparison with
the rates that were in place in December of 1995, that is, prior to the
4.4% across-the-board increase that was implemented according to the
Stipulation approved on November 30, 1995. Based on the concerns
previously expressed, we will implement a rate design procedure that
provides for a very slight decrease to one class, no change to another and
limits the maximum increase to 7.5%, which only one class receives. By
doing so, we have made some movement toward implementing marginal cost
based rate design, but have moderated the final result because of our
concerns with 1) data reliability, 2) the ability of any one class to
absorb this and the additional increases that are to occur over the next
three years, and 3) the validity of implementing marginal cost based rate
design in general and, in particular, when the amount of reconciliation
from marginal to embedded costs is as large as it is here. Our rate
design determination is shown on attached Exhibit 1. It moves each
customer class in the direction indicated by the EPMC-reconciled marginal
cost results, except for the two classes whose results indicated decreases
from test year rates. For these classes, we will decrease only the H-T
rate slightly, more in accordance with the marginal cost results, and the
SL/T class will remain unchanged. Given that additional increases are
scheduled to occur, we find it would be difficult for other classes to
absorb the additional increases that they would result from the two
classes' receiving greater decreases based on the cost information before
us. /11 We find further support for this decision in the comparison of
MPS's rates for the two classes that might have received decreases with
other Maine electric utilities (as reported on FERC Form 1, 1995) showing
that the rates are in line with those other Maine utilities for these
classes. /12 Our determination regarding the exact amount of rate change
for each class involves a fair degree of judgment, but it is designed to
implement the policy described above, while simultaneously arriving at the
correct amount of the total revenue requirement.
B. Rate Design Policy Issues
In the course of developing our rate design determination in
this case, we have made a number of observations about marginal cost rate
design methodology as it operated here. We would like to briefly note
these.
One of the most troubling features of this proceeding is the
size of the reconciliation gap. The EPMC markup for MPS is close to 100%.
First, with a price that is almost twice what the underlying economic
rationale says is it should be, the price signal being given is of
questionable value, especially for interclass pricing. Intraclass rate
design at least preserves marginal cost price ratios for seasons and time-
of-use periods, which probably has some merit, even if the absolute level
of prices greatly exceeds their underlying marginal costs. Second, the
EPMC will magnify the effects of any errors in marginal cost measurement.
To the extent that there are data problems, or other reasons to question
the reliability of the marginal cost estimates, it becomes more difficult
to use an EPMC reconciliation as a basis for rate changes. /13 Third, as
noted by the OPA's witness Smith, when a particular rate class has
proportionately more of a particular category of marginal cost in its
total class marginal costs, the EPMC will allocate other costs to that
class (from the revenue deficiency) in a way that appears be inappropriate
when viewed from the perspective of historical cost causation. Smith
argued strongly that under current conditions some features of marginal
cost rate design with EPMC are not serving their intended purpose. The
size of the EPMC adjustment appears to be one factor at least partly
explaining the novel treatments of customer costs advocated by Staff and
OPA, as well as OPA's novel reconciliation proposal.
Another troubling theme was Staff's lack of confidence in their
EPMC results, despite heroic and protracted efforts. Staff did not
believe that their study was reliable enough to justify any extensive
changes in class revenue responsibility. Data problems were certainly a
part of this, but we wonder whether there may also be infirmities in
marginal cost methodology, particularly in the measurement of
transmissions and distribution marginal costs, that create additional
uncertainties. Both OPA witness Smith and Staff witness Swan appear to
have misgivings about certain aspects of marginal cost allocation studies.
During examination, Swan questioned whether it is possible to determine
meaningful distribution marginal costs since the level of investment seems
to be more related to budgeting and availability of crews and other
resources. In addition, we are not completely satisfied with either of
the methods (vintage plant and reliability index) advocated here. The
lumpiness of investment is one problem, decline in load is another. We
wonder whether it is feasible to accurately separate transmission and
distribution investment into growth and reliability components.
This Commission first used a marginal cost study to allocate
revenues among rate classes in a CMP case, Docket No. 89-068. At that
time, most of the parties argued that the proponents of marginal cost
allocation had been unable to resolve problems of equity, stability,
continuity, and customer understanding. Supporters of the marginal cost
allocation argued that it was the most economically efficient approach. A
divided Commission accepted Staff's reasoning with one commissioner
dissenting on the use of marginal costs to allocate revenues among
classes.
Like this case, Docket No. 89-068 was fraught with
methodological and data validity concerns. The problems of excess revenue
allocation and rate stability continue and are more extreme here.
However, many of the difficulties in this case are different and were
unforeseen at the conclusion of Docket No. 89-068. It is not illogical to
expect that marginal cost studies of the future will continue to such
disputes.
We raise these matters because of issues that have arisen in
this case and because of the possibility that improvements may be found to
current rate design methodology that would address these concerns. We are
interested in receiving comments or proposals in future proceedings for
adjustments to current marginal cost rate design in this period of change
in the electric industry, as well as comments on the role and methodology
for rate design under current conditions, or suggestions regarding how the
Commission may best address these matters.
We are open to considering "rate design flexibility" proposals
wherein the Company would be permitted to set the exact rates for each
class anywhere within approved parameters at the time of its compliance
filing. The rates applied to the test year billing units would have to
equal the total company revenue requirement. The rationale for such a
process is to allow the Company some flexibility to set its prices, based
on its knowledge of its own customers, within reasonable limits. The
Company may be in a better position to understand how certain customer
classes might react to rate changes. Of course, setting the parameters
for such a proposal would have to be done with considerable care, and
could involve setting up a bandwidth within which rates could be found
reasonable, such as the degree of change between current and an approved
marginal cost result. Our consideration of any such proposal would
necessarily include a determination whether "rate design flexibility" is
consistent with Maine law and is in the public interest as a matter of
policy.
IX. CONCLUSION
We hereby approve changes in rate design for Maine Public Service
Company that are based to a degree upon marginal cost results from
evidence presented by the parties in this proceeding. We decline to move
rates to full EPMC results. Our decision to move only part way toward the
marginal cost results is based on our combined concerns about data
quality, methodology, and rate stability. Further, we invite the Company
to present updated NCP data for consideration in a limited proceeding to
determine whether further adjustments to interclass rate design are
warranted for implementation in February, 1998.
Accordingly, it is
O R D E R E D
1. That Maine Public Service Company shall file rate schedules in
compliance with the determinations contained herein.
Dated at Augusta, Maine, this 26th day of June, 1996.
BY ORDER OF THE COMMISSION
/s/ Christopher P. Simpson
Christopher P. Simpson
Administrative Director
COMMISSIONERS VOTING FOR: Welch
Nugent
Hunt
NOTICE OF RIGHTS TO REVIEW OR APPEAL
5 M.R.S.A. SS 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 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
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. SS 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.
SS 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 attached 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.
APPENDIX A
Procedural History
On February 10, 1995, the Company filed a 60-day notice of its
intention to file a general rate case and that it would file a request for
a 5-year rate stabilization plan, including a flexible pricing component
pursuant to SS 3195(6). On May 1, 1995, MPS filed a multi-year revenue
increase and rate stabilization plan. The plan included proposed rate
design changes in the form of class revenue requirements; no intraclass
rate element changes were proposed.
The intervention deadline was May 26, 1995. Intervention was granted
for the Office of the Public Advocate (OPA), Hannaford Bros. Co.
(Hannaford), and McCain Foods, Inc. (McCains) at the prehearing conference
held on June 9, 1995.
At the prehearing conference on June 9th bifurcation of the
proceedings and schedules for the revenue, rate plan and rate design cases
were discussed. The revenue increase and rate plan portion of the case
was scheduled for resolution by February 1, 1996. The rate design portion
of the case was initially scheduled for implementation by April 1. A
series of events resulted in several extensions of the schedule.
A Partial Stipulation (Flexible Pricing) was approved by the
Commission by Order dated August 7, 1995, resolving the flexible pricing
issues in this case. Under this plan, a discounted agricultural produce
storage rate proposed by the Company was approved on November 29, 1995, in
Docket No. 95-803.
Public witness hearings on MPS's proposed multi-year revenue
increases, rate stability plan and rate design were held on November 8,
1995 in Fort Kent and Presque Isle. Notice of the hearing was provided by
bill inserts, a Commission Notice and press release distributed to media
in MPS's service area.
An Order Approving Stipulation (Rate Case/Rate Plan) dated
November 30, 1995 approved a second stipulation establishing a multi-year
revenue requirement and rate stability plan for MPS to extend through
2001. The approved rate plan included an initial increase of 4.4% across-
the-board to all classes on January 1, 1996, and annual increases for the
next three years of 2.9%, 2.75% and 2.75% respectively. On December 19,
1995, a Supplemental Stipulation executed by Advocacy Staff, the Public
Advocate and the Company was approved without objection from non-signatory
parties. The Supplemental Stipulation addressed revenue issues related to
MPS's low income, Power Pact program.
Subsequent to its May 1, 1995 filing which contained the direct
testimony of Ward D. Gerow and an initial cost of service study, the
Company filed revised marginal cost of service studies, incorporating
various corrections and modifications, on June 29, 1995 and August 28,
1995. The Company also filed the rebuttal testimony of Mr. Gerow on
December 1, 1995 and his surrebuttal testimony on January 18, 1996.
Advocacy Staff filed the direct and surrebuttal testimony of Angela Monroe
and William Gibson, of the Commission Staff, and of Dale Swan and Daphne
Psacharopoulos of Exeter Associates, Inc., on October 11, 1995 and January
19, 1996, respectively. The OPA filed the direct, rebuttal and
surrebuttal testimony of Lee Smith of LaCapra Associates on October 11,
1995, December 1, 1995, and January 19, 1996. Depositions were taken of
Company representatives Ward D. Gerow, Edward Howard, and Tim Brown on
September 13, 1995 and the transcript was entered into the record.
A case management conference was held on March 12th and hearings were
held on March 14 and 15, 1995 at which all witnesses were cross-examined.
Briefs and reply briefs were filed by the Company, Advocacy Staff, OPA,
and McCains. Exceptions to this Report were filed by Advocacy Staff, OPA
and MPS on May 15, 1996. The Commission deliberated this matter on May
24, 1996.
End Notes
/ 1 Utilities, of course, have an obligation to stay abreast of
developments in Commission policy and regulation in their
industry.
/ 2 Following the rebuttal stage, the Company sought to provide
updated NCP data (from 1994 information) because it had then
extracted it from its records. It was excluded for being too
late in the process and would have required yet more resources
to be committed to the proceeding, then nearly completed. While
revisions and updates are not unacceptable during the course of
rate design proceedings, when substantial data and
methodological revisions are required, a heavy burden is imposed
on all parties to the proceeding, and some limits are necessary.
/ 3 In the early days of marginal cost methodology, it may have been
expected that future marginal costs would be above average cost.
In Docket No. 89-068, calculating final rates to recover CMP's
total revenue requirement required an approximately 30% mark-up
over marginal cost allocation results. In this case, the mark-
up will be close to 100%.
/ 4 See Order, Investigation of Central Maine Power Company's
Resource Planning, Rate Structures, and Long-Term Avoided Costs,
Docket No. 92-315(I), February 18, 1994, at page 1.
/ 5 The Commission recently confirmed that Docket No. 92-315(II)
will address rate design for CMP and will begin once this
proceeding is completed.
/ 6 In this case, the interest rate used to calculate the
amortization amount is derived from the utility's capital
structure and cost of capital. See Gerow Pref. Reb. Test., Ex.
10.
/ 7 A full exposition of this method can be found in NARUC's
Electric Utility Cost Allocation Manual (1992), pages 144-146.
/ 8 It could be noted that during the early years of PURPA and
marginal cost thinking it was believed that generation capacity
marginal costs were greater than historical costs. Under this
condition an EPMC reconciliation would "overallocate" other
kinds of costs to classes with relatively higher capacity
marginal costs. This may have been considered desirable by
marginal cost enthusiasts (a "right" price signal). What is
happening here with customer costs and allocation is exactly the
same methodological effect, but involving a different type of
cost and a different perception.
/ 9 This argument seems to be at odds with their position on the
capital customer cost issue, because sunk costs for meters are
also incurred at the margin (when the meter is installed) and
are largely related to new customers.
/10 Electricity Utility Cost Allocation Manual, National Association
of Regulatory Utility Commissioners, January, 1992.
/11 Of course, these two classes will receive at least 4.4%
decreases from the rates that they are paying today, which were
implemented with the across the board increase on January 1,
1996.
/12 The report of revenue (cents/Kwh) for the classes is as follows:
Large Industrial: MPS (H-T) 6.95, BHE 7.72, CMP 6.55
Lighting (Total): MPS 25.63, BHE 21.49, CMP 29.61
/13 To date, probably also for rate stability reasons, the
Commission has never implemented rates indeed based solely on
the EPMC calculated rate design results.
Maine Public Service Co. Exhibit 1
Docket 95-052
Revenue Requirement by Customer Class
Total EPMC Revenue
Customer Marginal Reconcil- % Require- %
Class Costs iation Increase ment Increase
Residential $11,188,882 $21,652,158 7.44% $21,268,554 5.53%
Commercial 4,632,058 8,963,724 12.05% 8,599,996 7.50%
ES/ES-T 4,154,354 8,039,296 5.08% 7,987,014 4.40%
EP/EP-T 921,687 1,783,602 2.96% 1,774,659 2.45%
S-T 1,344,991 2,602,759 -0.37% 2,638,428 1.00%
H-T 3,170,173 6,134,758 -11.08% 6,884,170 -0.22%
Municipal 143,149 277,015 23.90% 233,420 4.40%
SL/T 377,647 730,803 -8.41% 797,874 0.00%
Total $25,932,941 $50,184,115 4.40% $50,184,115 4.40%
Maine Public Service Co. Exhibit 2
Docket 95-052
Marginal Costs by Customer Class
Customer Class/ Total
Trans- Distri- Marginal
Generation mission bution Customer Energy Cost
Residential
$3,126,274 $171,611 $1,197,042 $2,209,199 $ 4,484,756 $11,188,882
Commercial
1,319,769 72,438 597,877 627,412 2,014,562 $ 4,632,058
ES/ES-T
1,240,016 68,064 581,668 83,301 2,181,305 $ 4,154,354
EP/EP-T
281,850 15,472 78,005 26,880 519,480 $ 921,687
S - T
519,525 28,516 0 15,015 781,935 $ 1,344,991
H - T
958,544 46,463 0 29,853 2,135,313 $ 3,170,173
Municipal
0 0 62,404 10,114 70,631 $ 143,149
SL/T
92,116 5,056 13,168 192,062 75,245 $ 377,647
Total
$7,538,094 $407,620 $2,530,164 $3,193,836 $12,263,227 $25,932,941
Exhibit 99(o)
MAINE PUBLIC UTILITIES COMMISSION
ELECTRIC UTILITY INDUSTRY RESTRUCTURING
Docket No. 95-462
REPORT
AND
RECOMMENDED PLAN
December 31, 1996
Chairman Thomas L. Welch
Commissioner William M. Nugent
Commissioner Heather F. Hunt
Executive Summary
On July 3, 1995, Legislative Resolve 1995, ch. 48 "Resolve, to
Require a Study of Retail Competition in the Electric Industry" became
Maine law. The underpinning of the Resolve is that broader market
competition and customer choice in the electric market will benefit the
public more than continued regulation. A central question of the Resolve
is how to facilitate development of a competitive market in the retail
purchase and sale of electric energy consistent with the public interest.
The Resolve directed the Commission to construct a plan for the
Legislature's consideration to achieve retail market competition for the
purchase and sale of electric energy in Maine. Today, we advance a
recommendation to restructure the market which fundamentally challenges
the historical method of delivering, purchasing and regulating the
provision of electric services. We embrace competition and advocate
cautious implementation.
The following fundamental principles guided the Commission's
recommended path to achieve retail competition by the year 2000:
* Where viable markets exist, market mechanisms should be preferred
over regulation and the risk of business decisions should fall on
investors rather than consumers.
* Consumers' needs and preferences should be met with the lowest costs.
* All consumers should have a reasonable opportunity to benefit from a
restructured electric industry.
* Electric industry restructuring should not diminish environmental
quality, compromise energy efficiency, or jeopardize energy security.
* All consumers should have access to reliable, safe and reasonably
priced electric service.
* Electric industry restructuring should not diminish low income
assistance or other consumer protections.
* The electric industry structure should be lawful, understandable to
the public, and fair and perceived to be fair.
* Electric industry restructuring should improve Maine's business
climate.
We believe our recommendation comports with these fundamental
principles and approaches industry restructuring in a manner that is
practical, efficient and in the public interest.
- 2 -
Our recommendation reflects our preference for competition and market
mechanisms. We believe the principal long-term benefit of our
recommendation is to shift the risk of business decisions about investment
in generation away from ratepayers and onto shareholders. Another
benefit is to bring competitive pressure to rates, which may move Maine's
electric prices closer to the national average. Our recommendation
reveals our desire to make the transition from theory to implementation in
a way that allows Maine to benefit from the experience of other states and
to preserve important state objectives.
In broad outline, we recommend the following:
Retail Competition and Deregulation
* Beginning on January 1, 2000, all customers would have the option to
purchase power in the competitive market.
* All customers would have the option to purchase power directly from
power suppliers or from intermediaries such as load aggregators,
power marketers or energy service companies.
* All customers could aggregate in any manner.
* Once customers can purchase power in the competitive market, the
Commission would not regulate, as public utilities, companies that
produce or sell power.
* The Commission would continue to regulate as public utilities the
companies that transmit and distribute electricity. These
transmission and distribution (T&D) utilities would have exclusive
service territories and an obligation to connect customers to the
power grid.
* Before 2000, the Commission would consider progress in other
jurisdictions and at the regional level in making the decisions
necessary to implement retail competition.
* The Commission would not require that other states or Canadian
provinces allow retail competition in their jurisdictions as a
condition to permitting suppliers from those states or provinces to
enter Maine's market.
- 3 -
Corporate Structure and Divestiture
* By January 2000, investor-owned utilities would transfer all
generation related assets to corporations distinct from their
transmission and distribution businesses.
* By January 2006, Central Maine Power Company and Bangor
Hydro-Electric Company would be required to divest all generation
assets. They could divest earlier.
* By January 2000, investor-owned utilities would be required to
transfer the rights to power from all qualifying facilities (QF)
contracts.
* Consumer-owned utilities would not have to structurally separate or
divest their generation assets.
* Contracts between investor owned utilities and qualifying facilities
would remain with the transmission and distribution utilities.
* Maine Yankee decommissioning liability would be collected in the
rates of transmission and distribution utilities.
* Investor-owned transmission and distribution utilities would not
market power. After 2006 Central Maine Power Company and Bangor
Hydro-Electric Company could not have affiliates that market power.
Maine Public Service Company may have such an affiliate, but it could
market power only in its service territory.
* After 2005, consumer-owned utilities could market power only within
their service territories.
Standard Offer
* Standard offer service would be provided to customers who do not
choose a competitive power provider and to those who cannot obtain
power in the market on reasonable terms.
* The transmission and distribution utility would administer a
competitive bid process to select the standard offer service
provider. Prior to a request for bids, the Commission would decide
the terms and conditions of the standard offer service.
- 4 -
* Standard offer service price would be capped so that the price for
power combined with the regulated rates of T&D utility service will
not, on average, exceed the total rate for electricity prior to
retail competition.
* If the standard offer service price plus the regulated rates of
transmission and distribution service is not, on average, at or below
the total rate for electricity prior to retail competition, the
Commission would investigate whether beginning retail competition at
that time remains in the public interest.
* The Commission would regulate the credit, collection, and
disconnection practices relating to standard offer service.
Customer Protection
* The Commission would regulate power suppliers' interactions with
customers, but not the prices or services offered.
* The Commission would regulate the transmission and distribution
utilities, including their rates and credit, collection, and
disconnection practices.
* The Commission would resolve customer complaints against transmission
and distribution utilities.
* Transmission and distribution utilities could not disconnect
customers from their systems for non-payment of charges by, or other
disputes with, power suppliers.
* If a power supplier terminates service to a customer, that customer
would default to the standard offer service.
* Upon passage of an electric restructuring plan by the Legislature,
the Commission would immediately begin customer education and
outreach programs.
- 5 -
Low Income Assistance
* The Commission strongly recommends that the Legislature fund low
income assistance programs through either the general fund or a tax
or surcharge on all energy services.
* If low income assistance is not funded through taxes, low income
programs would continue to be funded by ratepayers through the rates
of the T&D companies.
Energy Policy and the Environment
Renewable sources
* All companies selling power to retail customers in Maine should
include a minimum amount of renewable energy in their generation
portfolio.
* Power suppliers could meet minimum renewable requirements with
credits they could buy and sell.
* The Commission would consider the market's ability to develop and
sell power from renewable resources in establishing the renewable
portfolio standard.
Conservation and Load Management
* Ratepayers would continue to fund cost effective energy efficiency
programs through revenue collected in the rates of transmission and
distribution utilities.
* The transmission and distribution utility, with Commission oversight,
would select the energy efficiency service providers through periodic
competitive bidding.
Siting and certification
* The Commission would not review or approve construction of generating
facilities.
- 6 -
Environmental risk
* The Commission supports the application of air emissions standards
that minimize differentiation between old and new source generating
plants. The Commission will work with other states and appropriate
agencies to accomplish this goal.
Stranded Costs
* Utilities would have a reasonable opportunity to recover legitimate,
verifiable, and unmitigatable costs stranded as a result of retail
competition. Utilities should have only the opportunity for cost
recovery comparable to that under current regulation.
* The Commission would require utilities to take all reasonable steps
to mitigate those costs.
* The Commission would establish initial estimates of stranded costs
prior to 2000, using market information wherever possible. The
Commission would not reconcile stranded costs after the fact, but
would review them periodically and adjust them if warranted. The
stranded costs associated with QF contracts would be subject to
adjustment until the contracts end.
* Stranded costs would be collected from customers through the
regulated rates of the transmission and distribution utilities.
* To the extent generation-related costs incurred after March 1995
become uneconomic due to retail competition, the Commission would not
include any recovery for those costs in the stranded cost recovery
charge.
Regional issues
* The Commission endorses and will continue to work for reforms to the
governance of the New England Power Pool (NEPOOL) to allow fair and
meaningful representation for all market participants.
* The reformed NEPOOL should ensure that providers meet the North
American Electric Reliability Council reliability standards.
* The Commission endorses the establishment of an Independent System
Operator (ISO)to be responsible for the day-to-day operations of the
transmission system; the ISO must be effectively independent and have
no financial interest in any market participant.
* The Commission endorses the establishment of a voluntary power
exchange.
TABLE OF CONTENTS
I. INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . 1
II. RETAIL COMPETITION AND DEREGULATION . . . . . . . . . . . 4
A. Recommendation . . . . . . . . . . . . . . . . . . . 4
B. Discussion . . . . . . . . . . . . . . . . . . . . . 5
1. Existing Industry Structure . . . . . . . . . . 5
a. Regulatory system. . . . . . . . . . . . . 5
b. Development of competition . . . . . . . . 7
2. Retail Competition. . . . . . . . . . . . . . . 9
a. Description. . . . . . . . . . . . . . . . 9
b. Benefits, risks and uncertainties. . . . . 12
c. State and local economies. . . . . . . . . 15
d. Rural electricity consumers. . . . . . . . 18
3. Timeframe for Retail Competition . . . . . . . 19
4. Customer Access and Options . . . . . . . . . . 23
a. Simultaneous access. . . . . . . . . . . . 23
b. Available options. . . . . . . . . . . . . 25
c. Special meters . . . . . . . . . . . . . . 26
5. Reciprocity . . . . . . . . . . . . . . . . . . 27
C. Further Proceedings. . . . . . . . . . . . . . . . . 29
III. CORPORATE STRUCTURE AND DIVESTITURE . . . . . . . . . . . 32
A. Recommendation . . . . . . . . . . . . . . . . . . . 32
B. Discussion . . . . . . . . . . . . . . . . . . . . . 34
1. Need for Divestiture. . . . . . . . . . . . . . 34
a. Power production and sales . . . . . . . . 34
b. Other services . . . . . . . . . . . . . . 39
2. Authority to Order Divestiture. . . . . . . . . 39
3. Process for Divestiture . . . . . . . . . . . . 41
4. Separation of Qualifying Facilities & Maine
Yankee Power . . . . . . . . . . . . . . . . . 42
a. Qualifying facility contracts. . . . . . . 42
b. Maine Yankee . . . . . . . . . . . . . . . 44
5. Maine Public Service Company. . . . . . . . . . 46
6. Consumer-Owned Utilities. . . . . . . . . . . . 47
C. Further Proceedings. . . . . . . . . . . . . . . . . 49
IV. STANDARD OFFER. . . . . . . . . . . . . . . . . . . . . . 50
A. Recommendation . . . . . . . . . . . . . . . . . . . 50
B. Discussion . . . . . . . . . . . . . . . . . . . . . 51
1. Need for Standard Offer Service . . . . . . . . 51
2. Provider of Standard Offer Service. . . . . . . 52
a. Competitive bid. . . . . . . . . . . . . . 52
b. Bidding process. . . . . . . . . . . . . . 54
c. Standard offer service territories . . . . 56
d. Availability of information. . . . . . . . 57
3. Price Cap on Standard Offer Service . . . . . . 59
4. Terms and Conditions on the Standard Offer. . . 61
C. Further Proceedings. . . . . . . . . . . . . . . . . 63
V. CUSTOMER PROTECTION AND LOW INCOME ASSISTANCE . . . . . . 65
A. Recommendation . . . . . . . . . . . . . . . . . . . 65
B. Discussion . . . . . . . . . . . . . . . . . . . . . 66
1. Oversight of Generation Providers . . . . . . . 66
a. Registration and reporting . . . . . . . . 68
b. Business practices . . . . . . . . . . . . 69
c. Filing requirements. . . . . . . . . . . . 70
d. Standard billing . . . . . . . . . . . . . 70
e. Dispute resolution . . . . . . . . . . . . 71
2. Credit, Collection, and Disconnection . . . . . 71
3. Low Income Assistance Program . . . . . . . . . 72
4. Customer Education and Information. . . . . . . 75
C. Further Proceedings. . . . . . . . . . . . . . . . . 76
VI. ENERGY POLICY AND THE ENVIRONMENT . . . . . . . . . . . . 79
A. Recommendation . . . . . . . . . . . . . . . . . . . 79
B. Discussion . . . . . . . . . . . . . . . . . . . . . 80
1. Energy Policy and Electricity . . . . . . . . . 80
2. Renewable Resources in Electric
Power Generation. . . . . . . . . . . . . . . . 83
a. Perspective. . . . . . . . . . . . . . . . 83
b. Renewable portfolio standard . . . . . . . 85
c. Resource mix disclosure. . . . . . . . . . 88
3. Efficient Use of Electricity. . . . . . . . . . 90
4. Long Term Resource Planning and
Certification of Need . . . . . . . . . . . . . 92
5. Air Quality Impacts of Restructuring. . . . . . 92
C. Further Proceedings. . . . . . . . . . . . . . . . . 95
VII. STRANDED COST . . . . . . . . . . . . . . . . . . . . . . 97
A. Recommendation . . . . . . . . . . . . . . . . . . . 97
B. Discussion . . . . . . . . . . . . . . . . . . . . . 98
1. Nature of Stranded Costs. . . . . . . . . . . . 98
2. Utility Recovery of Stranded Costs. . . . . . .100
a. Opportunity for recovery . . . . . . . . .100
b. Mitigation . . . . . . . . . . . . . . . .102
c. Cost recovery limitation . . . . . . . . .104
d. Constitutional authority . . . . . . . . .106
3. Determination of Stranded Cost Charges. . . . .107
a. Process. . . . . . . . . . . . . . . . . .107
b. Methodology. . . . . . . . . . . . . . . .110
4. Recovery Mechanisms and Rate Design . . . . . .111
C. Further Proceedings. . . . . . . . . . . . . . . . .113
VIII.REGIONAL ISSUES . . . . . . . . . . . . . . . . . . . . .115
A. Recommendation . . . . . . . . . . . . . . . . . . .115
B. Discussion . . . . . . . . . . . . . . . . . . . . .116
1. Perspective . . . . . . . . . . . . . . . . . .116
2. Reliability . . . . . . . . . . . . . . . . . .117
3. Governance Issues in NEPOOL Reform. . . . . . .119
4. The Independent System Operator . . . . . . . .119
5. Transmission Pricing and Access . . . . . . . .120
6. The Power Exchange. . . . . . . . . . . . . . .122
7. Horizontal Market Power Study . . . . . . . . .124
C. Further Proceedings. . . . . . . . . . . . . . . . .125
TABLE OF APPENDICES
1. Legislative Resolve
2. Proposed Restructuring Legislation
3. Implementation Proceedings and Schedules
4. Survey of Residential and Small Business Customers
5. Estimates of Stranded Costs
6. Resolve Transition Issues
7. Customer Perspective
8. Restructuring Activities in Other States
9. The Deregulation Experience: Lessons Learned for Electric Power
Industry (National Regulatory Research Institute, August, 1996)
10. Public Advocate's Consumer Working Group Recommendation
11. Commenters
12. Glossary of Abbreviations
I. INTRODUCTION
This document advances the Commission's recommendation for electric
utility industry restructuring in Maine. An outline of the recommendation
is attached in the Executive Summary.
Legislative Resolve 1995, ch. 48 "Resolve, to Require a Study of
Retail Competition in the Electric Industry" became law on July 3, 1995.
Through the Resolve, the Legislature directed the Commission to begin to
study restructuring Maine's electric utility industry no later than
January 1, 1996 and to submit a report to the Legislature by January 1,
1997. The Commission initiated the study through a Notice of Inquiry on
December 12, 1995. To obtain the proposals and views of various
stakeholders, the Commission solicited and received written comments.
Twenty-two parties filed initial comments, and 11 filed responsive
comments. Thirty-five parties filed comments on the Draft Plan issued
July 19, 1996. Eleven filed reply comments.
The Commission used a variety of means to gather public opinion.
Specifically, the Commission held a series of roundtable discussions with
various interest groups; created a "homepage" on the World Wide Web to
share information and receive comment; held a total of nine public
hearings around the state, in May and September; issued four restructuring
bulletins; met with groups of small business owners; produced, in
cooperation with Time Warner Cable Company, a television program called
"Electricity: Can We Cut Your Bill?," which was shown on cable public
access channels throughout Maine; conducted formal surveys of both
residential and small business customers to learn more about their
attitudes, expectations and information regarding retail competition; and
participated in regional and national conferences on electric utility
restructuring.
The recommendation follows careful consideration of the positions and
arguments articulated throughout this process, a study of activities in
other states and the vast literature on industry restructuring.
The following fundamental principles guided the Commission's
recommendation to achieve retail competition by the year 2000:
* Where viable markets exist, market mechanisms should be preferred
over regulation and the risk of business decisions should fall on
investors rather than consumers.
* Consumers' needs and preferences should be met with the lowest costs.
* All consumers should have a reasonable opportunity to benefit from a
restructured electric industry.
* Electric industry restructuring should not diminish environmental
quality, compromise energy efficiency, or jeopardize energy security.
* All consumers should have access to reliable, safe and reasonably
priced electric service.
* Electric industry restructuring should not diminish low income
assistance or other consumer protections.
* The electric industry structure should be lawful, understandable to
the public, and fair and perceived to be fair.
* Electric industry restructuring should improve Maine's business
climate.
The Commission believes the recommendation comports with these
fundamental principles and approaches industry restructuring in a manner
that is practical, efficient and in the public interest.
II. RETAIL COMPETITION AND DEREGULATION
A. Recommendation
On January 1, 2000, electricity customers in Maine would have
the option to choose their power supplier, that is, the entity that sells
electric power as distinct from the entity that delivers the power over
wires and other facilities. All customers, regardless of size, type, or
location, would have the opportunity to elect a power supplier effective
on the same date. Customers could contract with power suppliers, purchase
from power exchanges and spot markets, and aggregate in any manner they
elect. Customers would not need special meters to choose their power
provider.
After retail competition begins, Maine would no longer regulate,
as public utilities, companies that generate or sell electric power.
Regulated public utilities would provide electric transmission and
distribution (T&D) services. The T&D utilities would have to allow
generation service providers /1 to reach any customer within their
exclusive service territories. The Commission would retain regulatory
authority over the T&D utilities' rates and other activities.
The Commission would not require that other states or Canadian
provinces allow retail competition in their jurisdictions as a condition
to permitting providers from those states or provinces to enter Maine's
retail market. Maine customers should have the opportunity to purchase
diverse products and services from providers in any location.
The Commission would watch closely other states' and regional
initiatives concerning retail competition. The Commission would
implement, or recommend to the Legislature as appropriate, changes to the
restructuring plan proposed here to the extent warranted by experience and
developments elsewhere.
B. Discussion
1. Existing Industry Structure
a. Regulatory system
Currently, the Commission regulates the electric
industry comprehensively. There is limited competition. This industry
structure developed because providing electricity had natural monopoly
characteristics, such as economies of scale, which suggested a single
entity could provide service at the lowest cost. As a result, electric
utilities have provided generation, transmission and distribution services
packaged or "bundled" together to all customers within geographic service
territories. As a substitute for competition, the government regulated
electric utilities to ensure they provided all customers with safe and
reliable service at just and reasonable rates.
Government imposed a system of regulation called "rate
of return" or "cost-of-service." It allowed utilities to collect
sufficient revenue to meet the legitimate costs of providing service,
including a fair return on necessary capital investment. Rate of return
regulation produced reasonable results for many years. In the 1970s,
however, high inflation, "oil shocks," and cost overruns for new
generating plants, primarily nuclear, increased rates. Because rate of
return regulation was based on actual utility costs, ratepayers, not
shareholders, carried the business risks of those events. As a result, in
the 1980s, regulators focused on "before-the-fact" reviews of utilities'
activities; utility commissions began to review utility proposals to
construct or purchase generating capacity and established rules for
utility resource planning. Nevertheless, the ratepayers continued to
carry the primary risks and benefits of power supply decisions.
In the late 1980s and early 1990s, Maine's electric
rates increased significantly for two principal reasons. First, utilities
were bound by contract to purchase power from qualifying facilities (QFs)
at rates which were based on estimates of future costs which turned out to
be too high. Second, an economic recession reduced electricity
consumption, which consequently decreased the revenue available to cover
the utilities' fixed operational costs. The rate increases suggested that
utilities were not operating as efficiently as possible and that
traditional regulatory tools, as applied in Maine, were ineffective at
keeping prices low. Moreover, utilities with high rates were vulnerable
to competition from different energy sources, such as self-generation and
other heating fuels. In Maine and elsewhere in New England, increases in
the price of electricity outpaced the increases in other regions of the
country.
Maine responded by adopting price cap regulation for
the electric industry. /2 The price cap approach focuses on price, not
the utility's underlying cost, and relies on indices, such as the rate of
inflation, to determine rate changes. Price cap regulation provides
utilities with pricing flexibility to meet competition and transfers more
of the business risks away from ratepayers and onto shareholders. Price
cap regulation has delivered predictable and stable prices to ratepayers.
For utilities, it has created incentives to minimize cost and allowed some
flexibility to compete for current and new customers.
b. Development of competition
Competition in the generation market began when
Congress enacted the Public Utility Regulatory Policies Act of 1978
(PURPA). That legislation was Congress's response to a series of oil
embargoes by the OPEC nations and to forecasts that the world was rapidly
depleting known oil reserves. PURPA encouraged cogenerators and small
power producers to produce energy efficiently and using renewable fuels.
/3 The PURPA requirements advanced a non-utility independent power
industry that proved entities other than utilities could provide
electricity reliably. New technologies suggested that electric generation
did not have significant economies of scale and could be delivered in a
competitive market.
A competitive wholesale market developed in which
independent power producers and utilities in New England and Canada
competed to provide power to retail utilities. For example, the Maine PUC
required utilities to buy the power needed to serve their customers
through a competitive bid process. However, because utilities that owned
transmission were not generally required to allow competitors to use their
systems, competition in the wholesale markets was not robust. Further,
the pricing of transmission distorted the wholesale market. To encourage
more effective competition in wholesale generation markets, Congress
enacted the Energy Policy Act of 1992 (EPAct). EPAct broadened the class
of independent power producers and required utilities that owned
transmission to allow competitors to use their systems for wholesale
transactions.
Pursuant to EPAct, the Federal Energy Regulatory
Commission (FERC) adopted rules to promote competition in wholesale
markets. FERC Order No. 888 (April 24, 1996). FERC required transmission
utilities to provide competitors the use of their system, for wholesale
transactions, on terms comparable to what utilities provide themselves.
FERC also required all utilities to file "open access" transmission rates.
/4 In addition, New England utilities and others are developing a
transmission pricing system to create uniform prices and terms for
transmission throughout the region. /5 The goal of these Federal and
regional efforts is effective competition in the wholesale market.
Currently, electricity prices in the wholesale market
are low, due in part to excess generating capacity in New England. The
excess capacity is the result of utilities preparing for an increased need
for power that never occurred due to the recession in the early 1990s.
New England's low wholesale prices, contrasted with high retail prices,
have increased pressure to deregulate the retail market. /6
2. Retail Competition
a. Description
A cornerstone of restructuring is to allow customers
to choose their power provider. Once customers can purchase power in the
competitive market, the Commission would not regulate, as public
utilities, entities that sell power. The Commission would regulate
entities that own transmission and distribution facilities ("T&D
utilities"). However, the T&D utilities would no longer buy power for
their customers. Customers would have the option to buy power directly
from power suppliers or from intermediaries such as a load aggregators,
power marketers or energy service companies.
The Commission would regulate as public utilities the
companies providing T&D services because they would continue to have
natural monopoly characteristics. /7 The T&D utilities' rights and
obligations would mirror many of those of traditional utilities. For
example, T&D utilities would have exclusive service territories and an
obligation to connect customers, with wires and other facilities, to the
regional electric grid. /8 T&D utilities would have to provide reliable
and safe service at regulated rates. Supplying power reliably depends on
distribution line maintenance and regional grid operation. Because a
regulated T&D utility would maintain the distribution system,
restructuring should not adversely affect its reliability. Restructuring
may, however, affect the reliability of the regional grid. /9
The T&D utilities would provide their services
separately from the companies providing power; customers would no longer
buy T&D services and power packaged or "bundled" from one company.
Customers would pay T&D utilities regulated rates and pay power providers
rates set by the market. /10 Each would charge customers separately;
however, T&D utilities and power suppliers could contract to include both
charges in one bill. This practice is common in the telephone industry,
where local exchange companies' bills often include the charges of
unaffiliated long distance carriers.
The Commission would establish the T&D utilities'
retail rates and rate design. /11 T&D utility regulation is likely to
occur through performance based regulation, such as price caps, not rate
of return-based regulation.
Although some commenters expressed varying degrees of
caution regarding the restructuring process, there is general support for
customer choice at the retail level.
b. Benefits, risks and uncertainties
Allowing customers to choose their power supplier
should create significant benefits to Maine and its consumers. Wholesale
competition holds the promise of lowering the cost of producing power.
Retail competition, however, will dramatically increase the number of
buyers in the power market. This increase alone should spur even greater
efficiencies (and lower prices) in power production. Economists generally
agree that competition works best when there are many buyers and many
sellers. Creating a direct market relationship between many sellers of
power and many buyers should also lead to creative service offerings:
better reliability for a premium price, for example, or less reliable
service at a discount. Customers will also have the opportunity, either
alone or through associations or brokers, to negotiate credit and risk
management instruments better tailored to their needs than the products
that are generally available under regulation. /12
Just as important, for Maine in particular, retail
competition and the deregulation of power production would transfer
business risks associated with power generation away from ratepayers and
onto investors. Shareholders, not ratepayers, would suffer financial loss
if the plants they build, or the contracts they execute, lose value due to
changes in the marketplace. Companies that make wise business decisions
will thrive, while those that make poor decisions may fail. /13 No matter
what companies win and what companies lose, Maine is likely to benefit by
shifting investment risk from ratepayers to shareholders. The cost of
power in Maine would be determined by the price in the regional and
perhaps national competitive market and not by whether Maine's utilities
or regulators predict the future accurately.
These benefits will occur provided there are effective
markets and vigorous competition. Most benefits from retail competition
would occur gradually over several years, from innovation and efficiencies
as providers construct new plants and tailor their services to meet
customer needs. Other benefits, such as lower costs from increased
incentives to operate plants more efficiently, will come sooner. The size
of the ultimate customer benefit is impossible to predict with confidence.
At least initially, however, most of the savings will be from lower power
production costs, costs that represent less than one third of today's
typical customer's electric bill. While there may be savings in other
areas, such as increases in transmission and distribution efficiency and
reductions in the amount needed to pay stranded costs, /14 these other
savings are not directly related to retail competition.
No change as basic and extensive as the deregulation
of power production and retail competition is free from risk or
uncertainty. There is no qualitative or quantitative analysis that can
prove retail competition will, in fact, reduce the total cost of producing
and delivering power or whether all customer groups will benefit from cost
reductions. For example, the cost of capital to finance new power
production facilities is likely to rise because investors could no longer
place the risk on ratepayers. Similarly, no tool exists to determine with
certainty whether competition among generation providers will decrease the
reliability of the electric grid. Nor can we predict with complete
confidence whether sufficiently robust markets will develop to avoid
anti-competitive behavior, or whether prices will become too volatile. It
is possible, but not certain, that funding for research and development of
generation technologies will decrease. /15 There is also a risk that
retail competition could initially create customer confusion about pricing
and new options, limiting the extent to which many customers could
benefit. On balance, however, it is reasonable to conclude that retail
competition will be more beneficial to consumers than regulation.
c. State and local economies
Expanding the power market and allowing customers to
select their power supplier could improve Maine's economy. Retail
competition could improve Maine's business climate by reducing electricity
rates below where they would be under the current form of regulation. As
importantly, retail competition and the deregulation of power suppliers
should reduce the disparity between Maine's rates and those in other
states. Maine's rates, like those throughout New England, are
significantly higher than those in other regions. /16 Expanding the
market from which retail customers can buy power and reducing the price
impact from specific regulatory decisions should move Maine's rates closer
to the national average. Allowing Maine companies the opportunity to
purchase power at prices comparable to those elsewhere, and thus compete
more effectively, would improve Maine's ability to attract and retain
businesses.
Deregulating power production could affect local
economies as well. Clearly, municipalities would benefit from moving
their own power costs closer to the national average. Their economies
would also improve if local businesses and residents achieved similar
savings.
Deregulation would, however, have tax implications for
municipalities with power production facilities in their tax base.
Deregulation would change the way in which municipalities assess the value
of those facilities, and thus the associated property tax assessments.
Specifically, municipalities often base property tax assessments of power
production facilities on book or accounting value as a proxy for market
value. When power production facilities are no longer owned by a
regulated utility, they will likely have a readily identifiable market
value. The market values, and consequently tax assessments, could be
higher or lower than those based on book value. Also, power production
facility owners would have a greater incentive to pursue lower tax
assessments than did regulated utilities, which passed tax increases on to
ratepayers. /17 Municipalities should anticipate these property tax
implications. If the competitive market creates an immediate,
disproportionate and negative tax effect on some communities, the
Legislature could act to mitigate the level and pace of tax consequences.
/18
Deregulating the production and sale of power could
affect Maine's paper and biomass industries. Because paper companies
consume vast amounts of power, lower rates and diverse services and
products would, over the long term, decrease their production costs and
improve their financial health. Maine's paper companies' ability to
compete successfully within their industry influences their ability to
preserve and create Maine jobs. Besides consuming power, paper companies
generate power from cogeneration and hydro facilities and sell it into the
wholesale market. Maine also has a substantial biomass industry that
produces renewable power and provides a market for the waste from Maine's
wood products sector. Many paper companies and biomass generators have
contracts to sell to utilities that power at prices well above the market
rate. Nothing inherent to restructuring justifies abrogation or
involuntary modification of contracts. However, when the contracts
expire, the paper companies and biomass generators would lose the
guaranteed buyer for their power. This is not a result of competition;
under current regulation, the contracts have little, if any, chance to be
renewed at current rates. While these companies would likely have an
opportunity to sell power into the regional market, market prices would
probably fall below current contract rates. Some customers may, however,
be willing to pay a higher price for renewable or environmentally benign
power. Ultimately, the long term benefits of competition for all
companies should outweigh the loss of benefits in the near term for those
companies with large contracts.
d. Rural electricity consumers
Retail competition should offer rural and urban
customers comparable benefit. Some commenters questioned whether
competition would harm residents in rural Maine. The restructuring
principles that guided our decisions reflect our concern about rural
residents. Specifically, we believe all consumers should have a
reasonable opportunity to benefit from retail competition.
Price disparities between rural and urban customers
are unlikely for two reasons. First, a substantial portion of each
customer's bill would be for T&D services that are price regulated and
location blind. Second, a customer's location is largely irrelevant to
power suppliers absent significant transmission constraints; these do not
disproportionately affect rural areas.
3. Timeframe for Retail Competition
All customers should have the opportunity to choose a power
supplier on January 1, 2000. /19 Most commenters, and the Paradigm, /20
concurred with that date.
Beginning retail competition in January 2000 has several
advantages. Maine would have an opportunity to observe successes and
failures in other states. Several New England states currently intend to
implement retail competition, for some or all customers, in 1998. /21
Waiting until 2000 should provide the opportunity to assess whether viable
markets develop and whether the mechanics for retail competition will be
successfully designed and implemented.
A 2000 start date would also allow critical regional
initiatives to be completed and tested. Such initiatives include creating
an independent system operator of the transmission grid, agreeing on rules
for transmission access and pricing, and reforming the New England Power
Pool (NEPOOL) to include new power suppliers. /22 Without the successful
execution of these regional changes, fair and effective competition is
unlikely to develop in Maine. The Commission would carefully monitor
regional developments and ask the Legislature to delay beginning retail
competition if necessary regional mechanisms are not working successfully.
The time frame for beginning retail access also provides
significant benefits for addressing stranded costs. Within a few years,
the amount of stranded costs in Maine will diminish significantly. This
should lessen the controversy over stranded cost recovery, and, more
importantly, reduce the risk of projecting and calculating such costs
erroneously. The greatest calculation risk of stranded costs is
estimating the market value of utility generation assets and power
contracts. Valuing assets and contracts later will provide an opportunity
to observe transactions in the emerging markets, such as the sale of
generation assets. Moreover, because litigation over stranded costs is
possible, a later start date may allow Maine to watch costly litigation in
other jurisdictions before committing to a specific stranded cost
treatment. /23 That experience could reduce the potential for delay and
uncertainty inherent in litigation in Maine.
Another advantage to beginning retail competition in 2000
is to allow customers time to become educated about their role in a
restructured industry. The success or failure of retail competition will
not turn on whether a few will navigate well through a proliferation of
choices, options and services, but on whether the public as a whole does
the same. In short, ratepayers must become effective consumers for choice
to be meaningful. That will take time and considerable effort. /24
Finally, restructuring in 2000 corresponds with the
conclusion of Central Maine Power Company's (CMP) Alternative Rate Plan
(ARP). Coordinating the end of the ARP with the beginning of retail
choice would obviate the need for complex regulatory proceedings that
would arise if retail competition began later. Similarly, the year 2000
generally coincides with the end of Maine Public Service Company's (MPS)
current rate plan and Bangor Hydro-Electric Company's (BHE) pricing
flexibility plan.
Enron Capital and Trade Resource, National Independent
Energy Producers, Alliance to Benefit Consumers, and Conservation Law
Foundation argued that retail competition should begin earlier. They
suggested that by waiting until 2000, Maine customers will not benefit
from competition for several years. We agree that deferring retail
competition until 2000 creates the possibility that Maine customers will
receive the benefits of retail choice, either real or perceived, later
than in other jurisdictions. As noted, some New England states currently
intend to allow retail competition for at least some customers in 1998.
However, because the cost of power is only a portion of current electric
rates, and the efficiency gains of competition will occur over time, it is
unlikely that retail competition will substantially and immediately reduce
total rates, absent some form of cost-shifting. /25 In any event, if
there are significant immediate benefits from retail competition achieved
by another means elsewhere, Maine should, and could, accelerate retail
choice.
MPS, Eastern Maine Electric Cooperative (EMEC), and Madison
Paper Industries recommended that Maine set certain conditions before
introducing retail competition, such as the existence of mechanisms to
ensure regional reliability and proof of a viable competitive market. We
agree in principle, but disagree with their proposed remedy.
Specifically, we concur that solutions to regional issues
are necessary for a robust retail market. But we believe that waiting
until 2000 will afford Maine the opportunity to observe the regional
solutions at work and decide then whether they suffice to protect
consumers. Similarly, we concur that market power would frustrate the
ability of competitive pressure to lower rates. But to identify
conditions now, without the benefit of retail competition experience in
any other state, would require the Commission to predict, rather than
accurately evaluate, the market's development. Accordingly, the
Commission would complete a market power study in December 1998. If the
findings reveal a level of market power that would frustrate competition,
the Commission would recommend the Legislature modify Maine's approach.
MPS proposed that retail competition begin later in 2000
because stranded costs associated with its Wheelabrator-Sherman contract
will be significantly lower by then. We disagree. There is no need to
link retail competition to its contract. The stranded cost treatment we
propose would give MPS a reasonable opportunity to recover its purchased
power costs stranded by retail competition. Customers in MPS territory
would pay the costs through a stranded cost charge. MPS's proposal would
have the same customers pay the same costs in their bundled electricity
rates. This "distinction without a difference" does not justify delaying
MPS's customers' opportunity to choose a power supplier.
4. Customer Access and Options
a. Simultaneous access
Beginning January 1, 2000, all customers, regardless
of size, type or location, would have the opportunity to choose a power
supplier. Allowing all customers to choose a power supplier at the same
time is fair and should bring the full benefits of competition to Maine
sooner than a phase-in approach. Most commenters, and the Paradigm,
agreed that all Maine customers should have choice simultaneously. The
approach follows the restructuring principle that all customers should
have a reasonable opportunity to benefit from a restructured industry.
Several utilities suggested that allowing choice to
all customers at once could present logistic problems, such as
difficulties in developing and running new billing programs. The
utilities did not present specific information to support that assertion.
The start date of January 1, 2000, however, should provide sufficient time
to resolve the logistic problems associated with simultaneous retail
access for all customers. In the event experience in other jurisdictions
reveals practical problems of allowing all customers choice at once, the
Commission could stagger the start dates.
MPS and EMEC proposed to phase-in retail competition
and require small commercial and residential customers to take service
from the standard offer as a means to reduce customer confusion.
Specifically, MPS proposed that these customers take standard offer
service until 2006. We reject the proposal and disagree with the
rationale. We do not share the assumption that all residential and small
commercial customers will be "confused" by the opportunity to choose
suppliers. Consumers who may be confused by the market should not prevent
consumers who are not from choosing a supplier. Moreover, a phase-in
approach could increase customer confusion and complicate public education
efforts. In any event, standard offer service, as an option, would be
available to counter any customer confusion.
b. Available options
The Commission would not proscribe or limit market
options. For example, customers and power suppliers could enter bilateral
contracts of any duration and on any terms. Customers could also purchase
on a shorter term "spot market," using a power exchange.
Customers could aggregate at will. "Aggregation" is
the organization of customers into groups to purchase power at more
attractive prices and terms than an individual customer could get alone.
Aggregation will likely be an important means for small customers to
obtain more attractive prices in the near term; larger demand generally
increases buying power, and provides opportunities to create attractive
load characteristics. Therefore, aggregation may give residential
customers and small businesses who might not fall in the marketing
mainstream prices comparable to those offered to large users.
Customer aggregation may occur in many ways. For
example, municipalities could aggregate residents' load. /26 Trade
organizations could aggregate their members' load. Customers could
organize into buyer cooperatives. Finally, electricity marketers could
combine individual loads and offer lower cost power.
As part of the public education before retail
competition, the Commission would inform customers, customer groups and
municipalities about aggregation. Customers who understand their options
are a critical component of effective competition.
c. Special meters
Special meters should not be a precondition for
allowing retail competition. Some commenters suggested special meters,
which measure customer demand and usage in small time increments, may be
necessary for bilateral arrangements and other benefits of retail
competition. However, there is no evidence that this is a necessary
precondition to successful retail competition. The use of average load
curves or other estimated usage data should be a workable alternative to
special meters. Such an approach should allow generation providers to
market services that do not require special meters. Other states'
experience should reveal any issues about special meters that are not
apparent at this time.
Some power suppliers may require that their customers
have particular meters or may provide them as part of their service. /27
Alternatively, some customers may find that certain meters minimize power
costs by, for example, targeting purchases to low cost hours. Ultimately,
the market would decide if customers need special meters.
5. Reciprocity
The Commission would not require that other states or
Canadian provinces allow retail competition in their jurisdictions as a
condition to permitting suppliers from those states or provinces to enter
Maine's market. Maine customers should have the opportunity to purchase
diverse products and services from any supplier in any location. The
number of suppliers in the market directly affects the level of
competitive pressure on rates.
Utilities have proposed a reciprocity requirement to
prevent power suppliers from states that have not authorized retail
competition from competing in Maine. They rest their proposals on the
need to mitigate revenue losses, and possibly reduce stranded costs. We
disagree that reciprocity should be required. Retail competition should
begin in Maine when there is a viable, functioning electricity market.
The utilities (or, more precisely, the companies who acquire the
generation now owned by Maine's utilities) will continue to be able to
sell into the wholesale market and the retail market at prevailing prices.
That we reject a reciprocity requirement does not diminish those
opportunities.
The independent power producers (IPPs) suggested a
reciprocity requirement to prohibit out of state power suppliers from
selling subsidized power in Maine. An example of such power is that
available from the quasi-governmental utility structure in Canadian
provinces or from states that do not allow retail competition. The IPPs
claimed such a requirement is necessary to ensure fair competition among
power suppliers. We disagree. To the extent other states or the Canadian
provinces allow their ratepayers to subsidize power sold in Maine,
consumers here will pay less, at least in the near term. The use of such
subsidies in a way that develops market power and forecloses competition
is not likely to be sustainable. Moreover, the Commission could not
identify with any confidence which power suppliers selling in Maine are
subsidized in other jurisdictions. Finally, to the extent any generation
provider believes a subsidy exists that is anti-competitive, it may seek a
remedy in the courts. /28
Moreover, reciprocity requirements have legal implications
for interstate and international transactions between Maine's customers
and providers in other states or the Canadian provinces. Attempts to
condition entry into the Maine market upon reciprocal treatment by other
states would likely be subject to court challenge on constitutional
commerce clause or other bases. A reciprocity requirement could be
considered economic protectionism of in-state power producers. Such a
requirement would burden interstate commerce and discriminate against
competitors located in states that have not adopted an electric industry
model acceptable to Maine. In cases where states have attempted to limit
or burden interstate commerce for the purpose of "simple economic
protectionism," the Supreme Court has established "a virtually per se rule
of invalidity." Philadelphia v. New Jersey, 437 U.S. 617, 624 (1978).
Even if it were determined that the purpose of the reciprocity requirement
were not simply the protection of private in-state economic interests,
such a requirement would still need to pass muster under the balancing
test enunciated in Pike v. Bruce Church, Inc., 397 U.S. 137 (1970). This
test requires that a legitimate local purpose outweigh the burden on
interstate commerce. Id. at 142. The Court, however, views state
reciprocity requirements for trade in other commodities unfavorably. See
Sporhase v. Nebraska ex rel. Douglas, 458 U.S. 941 (1982); Great Atlantic
and Pacific Tea Co., v. Catrel, 424 U.S. 366 (1970). /29
C. Further Proceedings
The Commission would implement retail competition and deregulate
power suppliers with caution and flexibility. The Commission would watch
closely restructuring in other states and participate in processes on the
regional and Federal levels to inform its implementation proceedings. If
it appears that retail competition should be delayed or accelerated, or
that other modifications are warranted, the Commission would, on its own
motion or at the request of an interested party, initiate an
investigation. All interested parties would have an opportunity to be
heard. If the Commission finds that any provision of the restructuring
legislation is not in public interest, the Commission would report to the
Joint Standing Committee on Utilities and Energy explaining the basis for
the conclusion so that the Legislature could consider modifying Maine's
approach.
The Commission would establish the revenue requirements that the
T&D utilities would be allowed to recover from ratepayers for their
services. The Commission would also determine the appropriate design of
rates for each T&D utility. While the Commission has traditionally set
rates for vertically integrated utilities, these proceedings would also
require that the T&D costs and rates be separated from the
generation-related costs of the utility. Once the T&D utility's revenue
requirement and rate design are determined, a price-cap plan or some other
form of incentive regulation could be adopted to provide the T&D utilities
with efficiency incentives and to provide ratepayers with stable and
predictable rates.
Significant issues to be determined in these proceedings are
likely to include cost of capital, the value of any assets transferred to
the generation subsidiary or other entity, rate design and marginal cost
of service, and the proper form of regulation for T&D utilities.
III. CORPORATE STRUCTURE AND DIVESTITURE
A. Recommendation
By January 1, 2000, Maine's investor-owned utilities (IOUs) /30
would transfer all generation-related assets and activities, including all
electric energy sales activities, to corporations distinct from their
transmission and distribution (T&D) businesses. After this date,
investor-owned T&D utilities could engage in generation-related businesses
only through a separate corporation. Maine's consumer-owned utilities
(COUs) /31 would not separate generation from T&D. Contractual
obligations between qualifying facilities (QFs) and electric utilities
would remain with the T&D utilities; however, by January 1, 2000, Central
Maine Power Company (CMP) and Bangor Hydro-Electric Company (BHE) would
sell the rights to the capacity and energy associated with their QF
contracts. Maine Public Service Company (MPS) would transfer these rights
to its generation affiliate.
By January 2006, CMP and BHE /32 would divest their generation
assets and related functions. The remaining T&D utilities would not be
affiliated with any company that owns generating facilities or sells
power. T&D utilities would maintain their contracts with QFs and could
own small, distributed generation facilities installed to minimize
distribution costs. MPS could maintain an affiliated generation company
after 2005, but only to provide retail service in its territory. MPS's
affiliate would not be permitted to construct or acquire ownership
interest in generating facilities, and would be permitted to make only
wholesale sales incidental to reducing costs of its retail service.
Maine's utilities would not be required to divest their
ownership in Maine Yankee unless the plant's operating life extends
significantly past 2008. To the extent they retain ownership after 2005,
CMP and BHE would be required to sell the rights to power associated with
that ownership. MPS's Maine Yankee entitlement would remain with its
generation affiliate. T&D utilities would retain the liability for
nuclear plant decommissioning costs.
After December 1999, T&D utilities could modify QF contracts but
could not extend the term of any contract or increase purchases pursuant
to any contract. Consistent with the prohibitions of T&D utility power
production and sales, T&D utilities could not enter new contracts with QFs
after December 1999.
CMP and BHE would transfer the rights to power they now hold
under contracts with QFs through competitive bidding. CMP and BHE would
complete the bidding in time to transfer all such power effective January
2000. To protect against the risk of changing market prices, CMP and BHE
would periodically resell these rights.
COUs would not be required to divest, or structurally separate,
generation from T&D and could continue to construct and own generation
facilities, and purchase and sell electric power. After 2005, COUs could
market electric power only within their franchise territories, and could
make only wholesale sales incidental to reducing costs of their retail
service. The Commission would limit the investments in and purchases of
power to those necessary to serve the COUs' own customers.
B. Discussion
1. Need for Divestiture
a. Power production and sales
BHE and CMP would be required to divest their
generation assets, except Maine Yankee, by 2006. After divestiture,
companies that own generation facilities would have no affiliation with
BHE and CMP. BHE and CMP would also be prohibited from selling power.
These requirements would ensure effective competition in the retail
market by reducing the T&D utilities' opportunities to exercise market
power.
Market power exists when one company can gain an
advantage over competitors through its affiliation with the provider of a
related service. If a T&D utility is affiliated with a power provider,
the T&D utility would have the incentive and the ability to use its
monopoly position in the T&D market to favor its affiliate. Favoritism
could take the form of "self-dealing" (i.e., favoring the affiliate when
purchasing services), steering customers toward the affiliate, or giving
the affiliate preferential access to information or T&D services.
Common ownership of power production facilities and
T&D is an impediment to effective competition. Removing the impediment
through divestiture, however, has costs. First, divestiture would impose
transaction costs including fees for investment bankers, attorneys,
accountants and other expenses. Next, divestiture creates the risk that
T&D utilities, and their ratepayers, will not realize the full value of
the assets because many generation assets could be on the market
simultaneously, or because the divestiture occurs when market values for
power production facilities are low. Accordingly, utilities would have
flexibility to plan and carry out divestiture over several years, and the
responsibility to minimize divestiture-related costs and risks.
Despite the costs and risks, the benefits of CMP's and
BHE's divestiture of their generating assets predominate. Effective
competition among generation providers is critical for consumers to
benefit from a right to choose suppliers. Effective competition depends,
in large part, upon the T&D utility being a neutral link between power
providers and customers. Ordering divestiture and prohibiting the T&D
utility from selling power into the retail market are necessary to ensure
the T&D utility serves as that neutral link.
Non-utility commenters, including the Office of the
Public Advocate (OPA), Conservation Law Foundation (CLF), independent
power producers (IPPs), and marketers agreed divestiture is needed to
ensure the market works effectively and efficiently. The Paradigm
recommended divestiture for Maine's IOUs. In addition, CMP has stated its
intent to divest before 2000.
BHE, MPS and Eastern Maine Electric Cooperative
(EMEC), however, believe divestiture is unnecessary. They argued that
functionally separating generation from T&D, and creating separate
subsidiaries or affiliates under a holding company structure would
suffice. They suggested that regulatory oversight of affiliate
transactions would prevent market abuse.
For several reasons, we believe structural separation
alone is inadequate. First, structural separation would require continued
regulatory oversight, which would depart from the restructuring principle
that, where viable markets exist, market mechanisms should be preferred
over regulation. Ensuring arms-length transactions in a competitive
market would protect customers more effectively than regulating affiliate
conduct. Reviewing, in the regulatory process, the details of multiple
and complex affiliate transactions would be cumbersome, litigious, and
expensive. Ultimately, it would protect consumers less effectively than
the direct price discipline of a competitive market. Divestiture would
allow competitive forces to replace regulation as the guarantor of
arms-length dealing.
Second, affiliated companies' incentives to take
advantage of joint ownership of power-producing and T&D facilities are
identical to the incentives in a vertically integrated utility. In fact,
the incentive for abuse in the affiliate model may be greater than the
incentive in the vertically integrated utility model under traditional
regulation because there would be no limit on the profit from power sales.
At the same time, regulators' ability to detect and remedy such conduct
would diminish. Specifically, under a subsidiary structure, there are
schemes that favor the unregulated generation company at the expense of
the T&D utilities' customers. These include using capital structures to
subsidize higher risk, non-regulated enterprises; "creative" accounting
for shared costs; preferential access to T&D customer information and
records; insufficient reimbursement to the regulated T&D utility for
personnel transferred to the unregulated subsidiary; expansion, or refusal
to expand, the transmission and distribution systems to the benefit of
affiliated generation companies over other competitors; and preferential
bundling of ancillary services. Such activities are difficult and
expensive to detect and correct through regulation or anti-trust
litigation.
The utilities argued that even if T&D utilities are
prohibited from owning generation, they should be allowed to sell power to
retail customers. We disagree. Permitting T&D utilities to sell power
would create the same problems as allowing them to own assets or companies
that produce power. A T&D utility would have the same incentive and
ability to favor its sales affiliate or partner.
To support its argument that T&D utilities should be
allowed to sell power to retail customers, BHE described the benefits it
could give customers by virtue of its knowledge of customers' needs.
BHE's comments, however, merely emphasize the risk of allowing the T&D
utility to sell retail power. BHE's knowledge of, and relationship with,
customers results from its public utility status; using those to advantage
its own power sales is precisely the kind of unfair advantage in the
market that no seller should have. Whatever useful customer information
the utility developed by virtue of its public utility status should be
available to all competitors in the market.
T&D utilities should continue to develop services,
information and customer expertise to deliver energy most efficiently to
customers of all energy providers. But transmission, distribution,
voltage regulation maintenance, and other core services /33 must be
available without undue discrimination to all customers and to all energy
providers to create and maintain an effective competitive energy market.
BHE and others suggested that regulation could resolve
issues arising from T&D utility involvement in selling energy to retail
customers. Again, we disagree. Regulation would not work any better over
a T&D utility retail power sales operation than it would over a T&D
utility power generation operation. Also, creating the need for more
regulatory oversight contradicts the principle that, where viable markets
exist, market mechanisms should be preferred over regulation.
The Commission would retain authority to allow T&D
utilities to acquire or continue to own small, distributed generation
facilities when that ownership would minimize distribution system costs.
The Commission would consider approving acquisitions case by case. The
T&D utilities would not be allowed to sell power at retail from a
distributed facility, and all revenue from sales at wholesale would flow
to the T&D utility.
b. Other services
There would be no blanket proscriptions of T&D utility
involvement in unregulated businesses. Except for power-related
operations, the issue of unregulated activities is separate from retail
competition. Questions about the range of services T&D utilities should
be allowed to provide and the types of subsidiaries and affiliates they
should be permitted to form cannot generally be answered in the abstract.
The Commission would, for the most part, consider those issues as they
arise in the same manner as it does today.
2. Authority to Order Divestiture
Historically, the generation, transmission and distribution
of electricity were considered natural monopolies requiring comprehensive
regulation to protect customers. Public utility regulation thus covered
the range of utility actions, including the purchase or construction of
major generation or transmission projects; the creation or dissolution of
subsidiaries and affiliated interests; oversight of affiliated and insider
transactions; bond issues, share offerings and other financial
transactions; and rates. In addition, the State determined utilities'
service territories.
Restructuring rests on the premise that electric generation
is not a natural monopoly and should not be provided and regulated as
such. However, T&D remains a natural monopoly service and would be
regulated accordingly. Under current law, the Commission must approve
utility proposals to build, purchase or invest in new generating sources,
or to enter into significant contracts for power. In Public Utilities
Commission, Re: Investigation of Seabrook Involvement's by Maine
Utilities, 67 PUR 4th 161 (MPUC, 1985), the Commission found it had the
authority to order Maine utilities to divest their interests in a nuclear
power plant. The Commission has also denied utility proposals to purchase
or construct power plants. Whether or not the Commission has current
statutory authority to order complete divestiture, however, it is clear
that the State, through the Legislature, may order divestiture or delegate
that authority to the Commission. /34
Some commenters suggested that mandatory divestiture may
violate the takings clause of the United States Constitution. On the
contrary, the United States Supreme Court found mandatory divestiture of
utility assets under the Public Utility Holding Company Act (PUHCA) SS
11(b)(1) does not violate that clause. See North America Company v. SEC,
327 U.S. 686 (1946). State-ordered divestiture raises no constitutional
issues different from those addressed by the Court in North America.
Moreover, although the takings clause could be implicated if forced
divestiture resulted in a substantial reduction in the value of investors'
holdings in the utility, the Commission would allow investors the same
opportunity as they have now to recoup the value of their holdings though
the stranded cost charge and the fair determination of the value of
divested assets.
3. Process for Divestiture
CMP and BHE should have the flexibility to complete
divesture over several years. Therefore, the Commission would permit a
two-step process. First, by January 2000, CMP and BHE would transfer
their generation assets, entitlements, and related activities to companies
structurally separate from their transmission and distribution businesses.
The Commission would determine, prior to retail competition, the degree of
separation necessary to protect T&D ratepayers and the competitive market.
Second, by January 2006, CMP and BHE would divest these assets,
entitlements and activities. CMP and BHE could propose to divest some or
all generation earlier. This flexible, two-step process would reduce the
risk of the T&D utilities, and ratepayers, receiving too little value for
these assets, and thus help reduce stranded costs.
The OPA, the IPPs, and the Industrial Energy Consumers
Group (IECG) argued for divestiture to occur sooner, on the grounds that
T&D utilities could behave, before 2006, in a way that would hinder the
development of a healthy competitive market. The IPPs and IECG proposed
no phase-in period; the OPA proposed divestiture by 2004. We are
persuaded that the likely benefits, in the form of lower stranded costs,
of a longer period with flexibility outweigh the likely harm to
competition during the transition. The concerns raised by these
commenters, however, underscore the need for Commission oversight of
utility affiliate transactions during the pre-divestiture period.
4. Separation of Qualifying Facilities and Maine Yankee Power
a. Qualifying facility contracts
Contracts between IOUs and QFs would remain with the
T&D utilities. BHE and CMP would periodically sell their output to the QF
power to the highest bidders. This periodic bidding would help reduce
errors in estimating stranded costs. MPS would transfer the output of its
QF contract to its generation affiliate.
The nature of the contracts between QFs and utilities
distinguishes them from other generating assets. The parties entered the
contracts pursuant to Federal and state policies. That the payment
obligations rest with utilities is a material term of the contracts.
Nothing inherent to restructuring requires abrogating that term. QF
investors would continue to have the opportunity to obtain their revenues
from a regulated utility.
Placing the QF contracts with the T&D utility, coupled
with periodic bidding for the power, also reduces the risk that stranded
costs relating to these contracts would be estimated incorrectly. If the
T&D utility divested the QF contracts, they would be held by entities not
linked to the T&D utility by common shareholders. This means that if
market conditions increase the value of power it would be difficult to
recover additional value from the unregulated company holding the
contract. If the estimate of value is made at the time of divestiture,
therefore, and market conditions change, the T&D utility would be unlikely
to be able to adjust its rates to reflect those changes. /35 By keeping
QF contracts with the T&D utility, the Commission could periodically
adjust the stranded cost rates to reflect changing market conditions.
Likewise, continuing opportunities for renegotiation and mitigation would
remain available to benefit ratepayers; these could be lost if QF
contracts move to another entity.
The IECG, the IPPs, and the OPA supported this
treatment of QF contracts. CMP opposed it and argued that QF contracts
ought to reside with the unregulated generation company. According to
CMP, QF contracts should be subject to the same risks as other generation
assets. The flaw in CMP's argument is that QF contracts are not like
other generation assets. CMP's shareowners now own the full economic
value of its power plants, together with the right to any associated
stranded cost recovery. Divestiture will not change that shareowner
value. If the plant is sold, shareowners will obtain the full economic
value (as proceeds of the sale) plus the right to associated stranded cost
recovery (if any) as shareowners of the T&D utility. If divestiture is
accomplished through a stock spin-off or similar transaction, the sum of
the value held by the deregulated owner of the plant and the value of the
stranded cost recovery allowed the T&D utility should be no less than the
value they hold today.
For QF contracts, however, there is another set
of shareowners, namely those now owning the right to the revenues. If
CMP's proposal is intended to reduce the certainty of those shareowners'
recovery, by exposing them to additional market risk, the proposal is
inconsistent with our conclusion that restructuring is not sufficient
reason to change the contracts. Under CMP's proposal, the stranded cost
revenues needed to pay the QFs and recovered by the T&D utility would flow
to the generation company. If those revenues are sent directly to the QF
owners, CMP's proposal is in all substantial respects identical to the
Commission's. If they are not, the increase in risk to the QFs cannot be
squared with law or equity.
b. Maine Yankee
The T&D utilities would retain nuclear plant
decommissioning obligations. The utilities would not be required to
divest their ownership interests in Maine Yankee, but would be required to
transfer the rights to the output to an affiliated generation company.
After 2005, BHE and CMP would be required to sell the rights to the output
to the highest bidder.
Maine Yankee entitlements present unique issues when
evaluating the value and practicality of divestiture. Maine Yankee's
operating license is currently scheduled to expire in 2008, two years
after the date by which CMP and BHE would be required to divest other
generation assets. CMP believes that divestiture's transaction costs and
other risks would not be justified given Maine Yankee's remaining license
life. CMP's arguments are persuasive. If Maine Yankee's operating
license is extended significantly beyond 2008, the Commission would
reassess whether divestiture should be required.
Some commenters expressed concern that leaving
decommissioning obligations with the T&D utility places the risk of
decommissioning cost overruns on ratepayers rather than investors. They
argued that if past amounts collected for decommissioning prove
inadequate, ratepayers will be responsible for shortfalls. Under Federal
law, however, divestiture cannot alter ratepayer exposure to this risk.
FERC establishes decommissioning rates. Under the "filed rate" doctrine,
state commissions cannot adjust them. The State has limited authority to
place the risk of decommissioning cost overruns on investors or to protect
against such overruns by increasing current or future decommissioning
funds in rates.
5. Maine Public Service Company
MPS should not be required to divest its generation or be
prohibited from purchasing and selling power as needed to serve customers
in its service territory. MPS would, however, be required to do these
activities through a separate subsidiary. After 2005, sales by MPS's
affiliate outside its franchise territory would be permitted only to the
extent necessary to minimize the cost of serving MPS's native load
customers.
Because it is small, the transaction costs for MPS to
divest could outweigh the benefits to MPS's customers. First, even though
customers' purchasing option may be fewer than elsewhere in Maine, even a
small number of competitors should reduce the risk that MPS could use
market power to its customers' disadvantage. Second, MPS's relative
isolation (MPS is not part of the New England Power Pool (NEPOOL)), raises
a concern about sufficient power supply. The Commission would
periodically review whether divestiture should nevertheless be required.
MPS agreed, arguing that forced divestiture might leave
northern Maine without a reliable and economic generation supply. MPS
also asserted that a forced sale would risk the loss of substantial value
associated with its Canadian subsidiary. According to MPS, the assets of
this subsidiary, principally a hydro-electric plant located in New
Brunswick (Tinker Station), could be expropriated by the Province with
reimbursement to MPS well below the assets' value. OPA, EMEC and others
supported exempting MPS from divestiture.
The IECG disagreed with granting MPS a blanket exemption
from divestiture, but would support exempting Tinker Station. IECG noted
that much of MPS's generation is located outside Aroostook County, and
within NEPOOL; this generation, at least, ought to be treated similarly to
that of CMP and BHE. The IECG also argued that it could be beneficial to
Aroostook County if restructuring made MPS less isolated from the rest of
New England. On balance, it appears that divestiture's transaction costs
would likely outweigh these benefits. Moreover, it is unlikely that,
absent divestiture, MPS's ownership interests in Maine Yankee and Wyman 4
would be large enough for MPS to have noticeable market influence.
Finally, nothing would prevent other retail power sellers from competing
in MPS territory; this will allow the market to determine the extent to
which MPS becomes more integrated into the New England market.
6. Consumer-Owned Utilities
COUs would not be required to divest generation assets and
would be permitted to continue to purchase and sell generation to serve
retail customers in their territories. COUs would have to limit power
purchases to the amount necessary to serve their customers. Like MPS,
after 2005, a COU would be permitted to sell outside its territory only
the incidental excess power acquired to serve its native load. This limit
would not modify or limit any current legal right COUs have to expand
their service territories or serve new customers.
COUs are smaller and serve fewer customers than most
investor-owned utilities and also have a fundamental difference of purpose
and governance that warrant different treatment. Specifically, an IOU is
a business managed to profit investors. COUs seek to provide the best
value to their members or customers, not to earn profit for investors.
COUs, including municipals and cooperatives, are directly answerable to
their members or customers through political or other channels not
available to customers of investor-owned utilities. The absence of the
incentive to maximize investor profit, combined with direct avenues of
redress for customer dissatisfaction, virtually eliminates the risk that
the COUs will use their power sales activity to the detriment of their
customers. Finally, although COUs may have tax or other advantages over
IOUs, these advantages benefit COU customers and are unlikely to harm
other customer groups.
The COUs agreed that they should be permitted to sell
power. The OPA and the IPPs also agreed but would prohibit COUs from
buying new generation. The Paradigm exempted COUs from separation and
divestiture requirements. CMP, BHE, and MPS, on the other hand,
disagreed. BHE and CMP asked whether allowing COUs to retain control of
and continue to purchase generation would give them a competitive
advantage. CMP claimed that today's small COUs could grow. The limits on
COU generation purchases and their lack of profit incentive should,
however, largely resolve concerns raised by these commenters. Absent
extraordinary and unforeseen growth, the impact of allowing COUs to own
and sell power either within their service territories or elsewhere is
slight.
C. Further Proceedings
The Commission would conduct a proceeding, beginning in
mid-1998, to establish the requirements for structural separation between
the T&D utilities and their generation-related activities. The Commission
would precisely define the parameters of structural separation necessary
to curb market power and cross-subsidization. Issues likely to arise
concerning structural separation include what codes of conduct need to be
established to ensure that the separation is effective, restrictions on
employee activities, accounting standards, and information and service
comparability requirements. Once separation standards are established,
each utility may be required to make a compliance filing.
CMP and BHE would file their plans for full divestiture prior to
2006. The Commission would review the plans and ensure their consistency
with the objectives of restructuring. A primary issue in these
proceedings would likely be whether the plan is reasonably designed to
capture the highest possible value.
IV. STANDARD OFFER
A. Recommendation
Standard offer service would be available to all customers who
do not choose a competitive power provider or who cannot obtain power in
the market at reasonable terms. From the customers' perspective, the
service would be comparable to that currently available from utilities.
The terms of the service would be simple and understandable. The
Commission would cap the standard offer rate so the cost of power and
transmission and distribution (T&D) services together does not exceed the
cost of electricity before retail competition. As the market matures, the
Commission would reevaluate the need for the standard offer, and its
structure.
The T&D utility would administer a competitive bid process to
select the standard offer provider for its territory. The T&D utilities
would solicit and evaluate bids and recommend a provider to the
Commission. The Commission would review the process, supporting
documents and finally select the provider.
Prior to the bidding, the Commission would establish terms and
conditions for standard offer service, including eligibility criteria,
requirements for entering and exiting the service, and credit, collection,
and disconnection provisions.
B. Discussion
1. Need for Standard Offer Service
Customers would receive standard offer service if they do
not elect or cannot obtain service from a competitive power supplier.
Standard offer service is power supply that when packaged with T&D service
would resemble service currently provided by utilities. For instance, the
Commission would approve the price and service terms and the customer
would receive one bill. Standard offer service departs from reliance on
the market, but provides a safeguard for the public during the transition
to competition. Most commenters supported some type of standard offer
service.
As experience in the evolving telecommunications industry
suggests, many customers may not have the immediate ability or interest to
elect alternative providers of services historically provided by a
monopoly. Customers opting not to choose may predominate, at least
initially, in the electricity market. Other customers, for financial or
other reasons, may not be able to obtain service from a competitive
provider on reasonable terms. The standard offer service should guarantee
that all customers have access to electricity service at a reasonable
price.
Bangor Hydro-Electric Company (BHE) and the National
Independent Energy Producers (NIEP) argued that standard offer service is
unnecessary because the retail market should meet the needs of all
customers. We are less confident that a fully competitive power market
will develop immediately. Even if the market developed quickly, customers
may be confused, at least initially, and make unfortunate, or even no,
choices about suppliers. The service would give customers time to adapt
to changes without the risk of immediate price increases.
At some point, it may be appropriate to reduce or end
government intervention in the competitive market. For example, if a
robust power market develops and sufficient market intermediaries emerge,
a more narrow standard offer may suffice, comparable to an "assigned risk
pool" in the insurance industry. As the market matures, the Commission
would reevaluate the need and structure of standard offer service.
2. Provider of Standard Offer Service
a. Competitive bid
The T&D utilities would administer a competitive
bidding process to select the standard offer provider in each of their
territories. Selecting the standard offer provider through bidding should
allow standard offer customers to benefit somewhat from competitive
pressure on rates. The Paradigm advanced a similar periodic bidding
approach; the Maine Equal Justice Project (MEJP), Alliance to Benefit
Consumers (ABC), Coalition for Sensible Energy (CSE), Enron Capital and
Trade Resources (Enron), and Maine's independent power producers (IPPs)
concurred.
The utilities urged that T&D utilities provide the
standard offer service and obtain power either through a bid process or
other mechanisms. They believe that method is simple, would reduce
customer confusion and would help them remain viable. More specifically,
Central Maine Power Company (CMP) proposed that the T&D utility would
provide the service on a "regulated basis" and get regulatory preapproval
of significant purchasing decisions so that it would be insulated from
major risks.
The IPPs proposed that T&D utilities provide the
standard offer service by getting bids for portions or "blocks" of the
standard offer load. The IPPs' proposal for standard offer "blocks" is
similar to the decremental avoided cost process used previously in
qualifying facilities (QF) bidding. /36 The IPPs claimed that approach
is essential to allow small power producers an opportunity to compete for
part of the standard offer load.
The issue is whether the market should decide who
provides standard offer service or whether the Commission should create a
scheme that follows present practice by granting the T&D utilities the
right to offer the service with regulatory oversight. One principle that
guided our decision making was that where viable markets exist, market
mechanisms should be preferred over regulation. We believe for several
reasons that the market would do a better job than regulators selecting
the provider.
First, the bid process would declare as the standard
offer provider the entity that can best combine supply resources and offer
the lowest price. There is no reason to assume that T&D utilities would
necessarily outperform the market. Second, the bid process, relying on
market forces, would minimize regulatory oversight of supply acquisition.
If the T&D utilities were automatically declared the standard offer
service provider, the Commission would have to decide whether the T&D
utility secured the best possible resource portfolio. One goal of
deregulation is to shift risk away from ratepayers and onto shareholders;
CMP's suggestion would preserve PUC protection of investments and continue
ratepayer risk. Third, industry restructuring should not, by design,
guarantee local utilities competitive advantages. Designating T&D
utilities as standard offer provider would almost ensure they initially
retain most customers. Finally, the standard offer service would supply
customers at a fixed price, without the customers' involvement in
selecting the provider. Customer confusion is of real consequence when
that confusion leaves them vulnerable to abusive or deceptive business
practices. By design, the standard offer shields customers from that
risk.
b. Bidding process
Each T&D utility would solicit, evaluate and rank
bids, and submit their recommendation, with supporting documents, to the
Commission. The Commission would review the materials and select the
standard offer provider. The winner would contract with the T&D utilities
to provide the service pursuant to Commission standards. Also by
contract, the T&D utilities would include, but list separately, charges
for the standard offer in their bills.
Power providers affiliated with a T&D utility could
bid to provide standard offer service in the utility's territory.
Similarly, consumer-owned utilities (COUs) could bid to provide the
standard offer in their territories. The IPPs argued that affiliated
generation companies should not be able to bid because there is too great
of a risk of self-dealing, cross-subsidization and anti-competitive
tactics. We agree there are some risks. The principal risk, in our view,
is not cross-subsidization, as the rates of the T&D utility and the
standard offer would be capped. Instead, the risk that the generation
affiliate would have an unfair advantage centers on its potential access
to T&D utility information. The short term remedy, until divestiture, is
for the Commission to ensure that the T&D's generation affiliate has only
the same information as every other potential bidder.
The Commission would decide many details of the
standard offer service in proceedings prior to 2000. For example, one
issue is the appropriate length of time between rebidding the standard
offer service. The Paradigm proposed bids occur every five years. Enron
urged the Commission to bid the standard offer every year. We decline to
choose a specific interval now. To define the length of service
commitment, the Commission would consider factors such as price stability,
market risk, and flexibility. The standard offer proceeding would also
address issues such as rate design, and customer class and voltage level
differentiation. Suppliers would offer other service terms in their bids.
Finally, some commenters expressed concern over
situations in which the standard offer provider fails to fulfill its
service obligations or if no entity submits a satisfactory bid. In the
standard offer proceeding, the Commission would consider means to protect
against a provider's failure to give service. For example, the Commission
could require the standard offer provider to post a performance bond. Or,
the Commission could direct the T&D utility to provide service through the
spot market pending selection of another provider.
As discussed below, if bids are above the cap, the
Commission would investigate whether retail competition is appropriate for
Maine at that juncture, and could recommend that the Legislature delay
competition. The Commission could also reconsider allowing the T&D
utility to provide the standard offer, particularly if only a few service
territories have unsatisfactory bids.
c. Standard offer service territories
Each T&D service territory would have a standard offer
service that may be supplied by different providers under terms unique to
each. This approach should encourage bidders to craft creative proposals
tailored to a territory's specific characteristics. That would serve
customers better than a one-size-fits-all package. It would also allow
the Commission to evaluate the merits of various service packages and
refine subsequent bidding processes.
The Office of the Public Advocate (OPA) suggested that
separate standard offer bids in each T&D service territory could result in
marked differences in prices due to variations in loads and customer
composition. Therefore, the OPA proposed, as an alternative, that Maine
be subdivided into four or six regions with about the same mix of
industrial, urban and semirural, and island/remote customer loads to
prevent inequitable distribution of benefits across the State.
The OPA's suggestion would at least complicate and
perhaps increase the cost of standard offer service without providing
offsetting benefits. Geographic cost differences are primarily a function
of transmission and distribution costs. Retail competition will not alter
that fact. Customer location should remain largely irrelevant to power
suppliers. The OPA did not couple its proposal with any persuasive
rationale for the view that standard offer bids coterminous with utility
service territories will cause substantial price variations. The OPA's
proposal would likely create administrative and practical obstacles
disproportionate to any benefit.
d. Availability of information
Before soliciting bids, T&D utilities would give
potential bidders customer information necessary to formulate an informed
bid. The Commission would decide what specific information the T&D
utilities should disclose from the general categories of customer load and
usage data, such as monthly demands and energy consumption, the number of
customers in each customer class and possibly general credit data,
including uncollectible revenue and the number of customer disconnections.
If the T&D utilities incur additional costs to develop and produce the
data they could recover those through rates.
To uphold individual customer confidentiality, the T&D
utilities would provide information in aggregate in a standard form. T&D
utilities would release customer-specific data only with permission by the
customer and there could be confidentiality protections. The T&D
utilities' possession of confidential customer-specific information and
perhaps other data may unfairly advantage their generation affiliates.
The same effect would result if a COU bid in its territory. The
Commission would restrict the type of information the T&D utilities may
disclose to employees of their affiliated companies or COUs that bid to
provide the standard offer.
CMP argued that it should not have to release
information it developed in its market research efforts. It claimed to
have gathered that category of information at considerable expense and
therefore argued it alone should use it for marketing purposes or sell it
for profit. We believe information utilities hold by virtue of their
status as providers of T&D services must be given to standard offer
bidders. /37 Other kinds of information, such as that which private
entities could obtain in other pursuits, would not be subject to mandatory
disclosure.
3. Price Cap on Standard Offer Service
The Commission would cap the standard offer so that its
price plus the regulated rates of the T&D service, including any stranded
cost charge, would not, on average, be higher than total electricity rates
just before the beginning of retail competition. The Commission would
consider whether the cap should escalate at an inflation-based index or by
another mechanism.
A cap on the standard offer service would test whether
retail competition will generally benefit all customer groups. If the
initial standard offer bids exceed the cap, it may be evidence that the
promised benefits of industry restructuring are illusory. In that case,
the Commission would investigate, with an opportunity for all to
participate, whether Maine should delay retail competition until it can be
certain that the new framework would not increase rates for what may be
most customers. Issues such as whether all or only some territories had
bids above the cap would be likely to affect the Commission's findings; if
bids in all territories exceeded the cap, that would certainly argue for
delay. The Commission would, of course, report the resulting
recommendation to the Legislature for its consideration.
The American Association of Retired Persons (AARP), MEJP,
and CSE supported a cap. AARP suggested the cap reflect 1995 rates. The
Paradigm proposed a cap based on the total cost of existing service. The
utilities, however, argued that setting a cap and using bid prices as a
litmus test for retail competition is improper and unworkable.
Specifically, BHE asserted that the Commission may be designing
deregulation process to fail by requiring that standard offer service be
no more expensive than 1999 retail electric rates. BHE and CMP suggested
that by 2000, without restructuring, rates might increase if, for example,
fuel prices rise. Therefore, CMP suggested it is more appropriate to
compare the standard offer bids to rates that would have been in effect
under regulation.
The utilities' argument has merit. The purpose of the
standard offer cap is to ensure restructuring does not harm Maine's
customers. Accordingly, rates that would have existed absent competition
are a fair comparison. However, that comparison would require a
counter-factual analysis that would be impractical or, perhaps,
impossible. /38 Therefore, the rates when retail competition begins are
the best proxy for what electric rates would be absent restructuring.
For several reasons, a standard offer cap based on the
rates in effect just before retail competition is workable and does not
portend failure. First, absent retail competition, generation costs
should decrease as purchased power contracts expire, generation assets
depreciate, and regulatory assets are reduced. Those decreases in costs
over the years make it reasonable to believe bidders could offer a rate
below the cap. Second, the Commission would consider escalating the cap
according to an index. Third, if all bidders exceed the cap, the
Commission would not automatically delay retail competition, but would
investigate whether it is in Maine's interest to wait. If there is
persuasive evidence that rates would have significantly increased absent
restructuring, it would be one factor to consider in deciding whether to
recommend delaying competition.
4. Terms and Conditions on the Standard Offer
The conditions and restrictions on the standard offer must
balance its purpose with the need to keep the price as low as possible.
The Commission would adopt standards governing the standard offer in the
general categories of eligibility requirements, entry and exit
restrictions and credit, collection and disconnection practices. As the
market matures and as customers become experienced energy buyers, the
Commission would amend the initial requirements accordingly.
For the standard offer to be effective serving those who
cannot obtain service on reasonable terms from competitive providers and
to allow customers time to adjust to competitive options, customers should
have flexibility to enter and exit the standard offer unimpeded by
restrictive policies, at least during a transition period. However,
allowing every user of electricity unfettered freedom to enter and exit
the standard offer may increase its cost. On balance, we are inclined to
allow few, if any, restrictions on entry or exit during the early years of
retail competition to encourage customers to experiment with the market.
Later, it may be appropriate to limit the number of times a customer may
enter and exit, specify times of the year when a customer may change
service, or charge a fee to reenter.
Further, we are inclined to exclude large customers, for
example those with loads over a specified amount, such as 1 MW. Large
customers tend to be sophisticated energy users and would probably have
competitive choices immediately. Therefore, the purpose of the standard
offer option does not apply. Also, if large customers could take standard
offer service, and if there were limited restrictions on entry and exit,
the cost of the service would likely increase for all customers. /39
Finally, we would adopt credit, collection, and
disconnection rules to govern the standard offer. The availability of
standard offer service would not relieve customers of the obligation to
pay for service. The standard offer provider would have authority to
disconnect a customer for nonpayment, but only pursuant to Commission
rules. Disconnecting customers who do not pay for service can avoid the
accumulation of uncollected debt that would increase the standard offer
service cost for other customers.
C. Further Proceedings
The Commission would, in proceedings beginning in late 1997,
establish terms and conditions (including the rate design) for standard
offer service, and would later (during 1999) review and approve the
selection of bidders to provide standard offer services in each of the T&D
utility service territories. There would be two groups of proceedings
related to standard offer services.
First, the Commission would conduct a proceeding to establish
terms and conditions for standard offer service, including eligibility
criteria, requirements for entering and exiting the service, and credit,
collection, and disconnection provisions.
Once the design of the terms and conditions of standard offer
service has been established, the T&D utilities would request bids from
power suppliers and would present the results of the bidding, together
with a recommendation, to the Commission. The Commission would review the
utilities' filings and would determine the winning bidders. These
activities would be completed by mid-1999 so that the standard offer
providers would have sufficient time to secure the necessary resources to
provide the service, and to establish customer service programs. Issues
in these proceedings would likely include whether the bidding process was
fair, and whether the bidders met reasonable standards for reliability and
financial security.
The Commission would review the winning bids for standard offer
service to ensure that the price of power, when added to the price for
other services (e.g., T&D) and the stranded cost charge would not, on
average, be higher than the electricity rates paid during 1999. In the
event that bids were too high to achieve this objective, the Commission
would consider whether it should recommend modifications to the process of
electric restructuring to ensure that regulation in Maine remains
consistent with the public interest.
V. CUSTOMER PROTECTION AND LOW INCOME ASSISTANCE
A. Recommendation
The Commission would adopt standards to govern the relationship
between customers and power suppliers. The subject matter would include
the power suppliers' registration to offer service, the obligation to
notify customers of price and term changes, and to file information with
the Commission. The Commission would have jurisdiction to resolve some
types of disputes between customers and power providers. The Commission
would have authority to investigate and remedy business conduct that is
abusive or anti-competitive.
The transmission and distribution (T&D) utilities and the
standard offer provider would have credit, collection, and disconnection
obligations comparable to those that currently govern utilities, with some
variation to reflect the changed marketplace. For instance, T&D
utilities would not disconnect customers for failing to pay their power
supplier. T&D utilities could, however, disconnect customers for failing
to pay for T&D or standard offer service.
The Commission strongly recommends the Legislature fund
electricity- related low income assistance through tax revenues. If it
elects not to, the Commission would continue to include low income
assistance in T&D rates.
The Commission would begin immediately to educate the public
about the opportunities and obligations of retail competition. In
addition to diverse education efforts, the Commission would require
utilities to separate charges for power from the remainder of the utility
bill beginning in January 1999.
B. Discussion
1. Oversight of Generation Providers
The Commission would regulate power suppliers' interactions
with customers, but not the prices or services they offer. Customers'
ability to select another supplier would replace regulation as the price
control system. Even where customer choice controls cost, there must be
some rules to govern the rights and obligations of both buyers and
sellers. Specifically, in the near term, customers would have to learn to
be effective consumers of a product they have never before bought in the
open market. Their inexperience may cause confusion or, worse, make them
vulnerable to suppliers who capitalize on that inexperience with devious
business practices. Indeed, the public reaction to competitive
opportunities in telecommunications suggests that the public wants, and
expects, some Commission oversight of new providers of competitive
services.
Accordingly, as detailed below, the Commission would
oversee power suppliers, including registration, business practices,
filing requirements, and billing formats. Similarly, the Commission
would adopt rules to govern credit, collection and disconnection issues.
Finally, because information is customers' best means to protect
themselves, a central role for the Commission will be to distribute
accurate and timely information to the public. Giving customers rights,
information and a forum for dispute resolution comports with the
principles that all customers should have a reasonable opportunity to
benefit from a restructured industry and that the industry structure
should be understandable and fair to the public.
Commenters generally supported Commission oversight of
power suppliers, but disagreed as to the appropriate level for a
competitive industry. Customer groups advocated extensive oversight.
Utilities and independent power producers believe unnecessary or
restrictive regulation would limit their ability to craft diverse service
offerings.
We are mindful that in a fully matured competitive market
where customers are experienced buyers, the need for regulations to
protect the public is minimal. For a market in its infancy, however, the
public interest calls for a heightened, even if temporary, level of
protection. When the market and customers become more seasoned, the level
may decrease. We agree with the utilities that customer protection
standards governing suppliers' conduct in Maine must respect their need to
create diverse offerings. Further, we believe that the standards in Maine
ought not be significantly more burdensome than those in other states.
The Commission would balance the needs of competitive suppliers with
consumer protection.
a. Registration and reporting
Power suppliers would have to register to sell to
customers in Maine, and file periodic reports after that. Registration
and reporting would serve several purposes. First, it would provide the
Commission with information on how many suppliers are selling into the
Maine market. Second, it would help the Commission monitor the market's
development. Third, it would allow the Commission to be a source of
information for customers.
Registration requirements would allow the Commission
to confirm for customers that power suppliers have the financial and
technical resources to carry out their business obligations and customer
commitments. Reviewing suppliers' information before they provide
service may enhance reliability and increase customers' confidence to
participate in the market.
The registration process would include an application
with information specified by the Commission, verified and filed by a
corporate officer. The Commission would likely streamline registration
for suppliers registered in other states.
As part of registration, the Commission would
consider requiring a bond. Bonding could deter providers who do not have
the financial ability or the intent to stand behind customer commitments.
Also, bonding could be evidence of financial ability to withstand market
disturbances or fluctuations or other events that may temporarily increase
the cost of providing service. Customers should have some confidence in
their supplier's financial ability to withstand such market fluctuations.
Central Maine Power Company suggested, and we agree,
that bonding might also cover the costs to ensure uninterrupted service if
a provider suddenly ceases operations or otherwise abruptly stops service.
In that event, the bond could pay costs incurred by the standard offer
provider and the T&D utility to continue service. Ultimately, bonding
could lower the cost of those services.
b. Business practices
The Commission would adopt minimum standards for
suppliers' conduct. The standards would include the following: minimum
notice provisions for changes in rates or other service terms, conditions
for service terminations, requirements governing a change in service
providers, minimum requirements for information and marketing materials.
The standards would make clear the responsibilities of suppliers that want
to sell to Maine customers. They would also give customers confidence
that the Commission would hold every supplier to uniform obligations. To
be effective, the Commission should have the authority to impose fines,
issue injunctions and provide other appropriate remedies for violations of
consumer protection standards.
In a competitive market, the Commission would turn
from comprehensive economic control to more narrowly tailored consumer
protection enforcement. Thus, the Commission would have the authority to
investigate and prosecute possible violations of Maine's Unfair Trade
Practices Act, 5 M.R.S.A. SS 205-A-214, involving the retail practices of
power suppliers. The Attorney General should retain authority to sue
under those statutes in court, and could assist the Commission to
investigate violations of the Act. The Attorney General should have
responsibility to enforce the Act for power suppliers in the wholesale
market.
c. Filing requirements
The Commission would require power suppliers with a
service generally available to the public, or a significant segment of the
public, to file their rates, terms and conditions. The Commission would
review the filings only to ensure that all terms and conditions comport
with business practice standards established by the Commission. The
filings would be part of the information resources available to the
Commission to help customers or to investigate and solve customers'
disputes with power suppliers. The Commission would not require suppliers
to file service contracts with individual customers.
d. Standard billing
Whether competition benefits customers depends in
large part upon their ability to make informed choices. That, in turn,
depends upon the availability of accurate, clear and timely information.
Therefore, the Commission would consider adopting a standard bill format
for power service. A standard bill format could perform the same
function for consumers as do nutrition content labels on food products: it
would help the consumer understand options, allow easier comparison of
different offers, and reduce the likelihood of deceptive marketing.
In developing a standard bill format, the Commission
would consider similar requirements in other New England states and may
encourage a consistent regional bill format. That approach could reduce
the administrative costs of compliance for suppliers throughout the
region, including Maine.
e. Dispute resolution
The Commission would resolve certain customer
complaints against, or disputes with, power suppliers. The Commission's
authority would be similar to that it currently exercises for public
utilities, modified to reflect the competitive market. Customers should
have one forum to help them resolve disputes with T&D utilities and power
providers.
2. Credit, Collection, and Disconnection
Retail competition will not relieve the consumer of the
obligation to pay for services. Nor will retail competition create the
possibility that customers will be disconnected except as provided by
Commission rule. The Commission would continue to govern the credit,
collection, and disconnection practices for the T&D utilities much as it
does currently for public utilities. /40 As discussed above, the
Commission would also create credit, collection and disconnection
standards for standard offer service providers.
The Commission would not authorize the T&D utilities to
disconnect customers for nonpayment of charges by, or other disputes with,
power suppliers. T&D utilities and power suppliers would be separate
services provided by different companies. If a customer fails to pay a
power supplier, the T&D utility would not be allowed to disconnect the
customer from its system. Power suppliers should face the same risk and
employ the same methods of debt collection as other competitive
businesses. Power suppliers would not be obligated to continue to provide
power to nonpaying customers. If the customer cannot find another
supplier, the customer would default to the standard offer service.
T&D utilities would have the authority, pursuant to
Commission rules, to disconnect customers who do not pay for T&D or
standard offer services. Disconnection avoids the accumulation of
uncollected debt that ultimately increases the costs of T&D and standard
offer service.
3. Low Income Assistance Program
The needs of Maine's low income citizens are independent of
the structure of regulation; for that reason, retail competition should
not itself reduce the availability of low income assistance. Currently,
Central Maine Power Company, Bangor Hydro-Electric Company and Maine
Public Service Company administer low income assistance programs paid for
by customers through rates. The percent of total rates that fund low
income assistance is small, about half of 1 percent of total revenues, or
less than $7 million per year.
The Commission strongly recommends that the Legislature
fund low income assistance programs through general taxes or a tax or
surcharge on all energy services. Most commenters supported funding low
income assistance through the tax system.
The Legislature should fund low income programs through the
tax system for several reasons. First, the tax system is a more equitable
means of collecting funds than electricity use because general taxes are
based on ability to pay rather than electricity consumption. Second,
government agencies created to provide social services may administer low
income assistance programs more effectively than T&D utilities, resulting
in greater benefits from the same amount of dollars. Third, funding low
income assistance through electric rates raises electric rates relative to
other energy alternatives, causing an uneven competitive environment among
different energy sources. A tax or all-energy-source funded program would
correct that imbalance.
A system funded by general revenues would also more
effectively balance income disparities among service territories. The
division by service territories of low income programs may
disproportionately burden customers in economically depressed areas
because low income assistance is needed most in areas where residents are
least able to support it. Because of the disparity between need and
revenues, it could be simpler and less controversial to deliver statewide
assistance under a general revenue system. The Commission, together with
the State Planning Office, would develop a recommendation and proposed
legislation for funding assistance to low income consumers of electricity
through the general fund or through a tax on all energy sources in the
State. This proposal would be provided to the Legislature by January 1,
1998.
The Industrial Energy Consumer Group (IECG) indicated
concern about funding low income assistance through the general fund. It
argued that it would subject vulnerable citizens to the risk that the
Legislature would not continue to support low income assistance. The IECG
believes funding low income assistance through rates is not as regressive
as other mechanisms, such as property taxes, because electricity
consumption tends to vary with income. The IECG also doubted that the
small amount of low income support in rates would distort the market.
We concur that low income citizens ought not be harmed by
restructuring. That view is reflected in the principle that restructuring
should not diminish low income assistance or other customer protections.
During the transition to a competitive market, however, it is appropriate
to reexamine subsidies and evaluate whether they are recovered by the most
equitable and efficient means.
In the event the Legislature elects not to fund low income
assistance through the general fund or through a tax designated for this
purpose, it could preserve the Commission's authority to fund low income
programs through electric rates. Then, the Commission would fund programs
in an amount comparable to that in rates in 1999. The Commission would
also investigate whether COUs should provide low income programs and
whether there are better means to distributing funds.
4. Customer Education and Information
Ratepayers must become effective consumers for choice to be
meaningful. To that end, commenters supported public education programs
to ensure Maine citizens understand retail competition, how choice would
affect them, and what they need to know to participate in the market. The
Commission would immediately begin public education, including, but not
limited to, holding public forums, publishing and distributing information
bulletins, and developing an information data base accessible to users of
the Internet. The data consumers might find useful are information from
suppliers' registration applications, terms and conditions of service
filings, and power portfolio disclosure statements. Beginning retail
competition in 2000 would enable the Commission to observe public
education efforts in other New England states and mirror those that appear
most effective.
The Office of the Public Advocate proposed that separating
or "unbundling" power charges from the rest of customers' utility bills
before 2000 would educate customers about retail competition. According
to the OPA, giving customers an opportunity to see their electricity bills
divided by services before retail competition would allow them to
understand the separation of costs between power and transmission and
distribution services. We agree. Accordingly, beginning in January 1999,
all utilities would separately identify charges for generation.
C. Further Proceedings
In mid-1998, the Commission would begin one or more proceedings
to determine what requirements should be imposed on companies selling
electric power to retail customers in Maine. The issues to be addressed
in these proceedings, which would be concluded by mid-1999, would likely
include what registration requirements are appropriate; what jurisdiction
the Commission should have over disputes between power sellers and their
customers; what penalties should the Commission impose for violations of
Commission rules; and what disclosures should power sellers make to their
customers concerning the characteristics (e.g., fuel mix) of their
production facilities. Other issues may be examined, including
performance bonding; notice requirements for rate changes, other terms,
and termination; and standard billing.
The Commission would also determine what credit, collection and
disconnection practices would be appropriate for T&D utilities. During
1997, the Commission would begin to review Chapters 81 and 86 of its
rules, dealing with its disconnection and deposit regulations for
residential and nonresidential customers respectively, and would complete
new rules appropriate for a restructured electricity market by the end of
1998. Issues in this proceeding would include the implications of a T&D
utility providing billing service for power providers, and whether
existing rules concerning credit and collection continue to be
appropriate.
During 1997, the Commission, together with the State Planning
Office, would prepare a recommendation, including proposed legislation,
for funding assistance to low income consumers of electricity through the
general fund or through a tax on all energy sources ("all fuels") in
Maine.
If the Legislature does not fund low income assistance through
tax revenues, the Commission would investigate whether ratepayer-funded
low income programs should exist in all service territories, and whether
the means by which utilities distribute funds should be amended.
The Commission would establish a comprehensive customer
education and outreach program beginning in 1997. The Commission would
intensify its customer education efforts in 1999, as the January 2000
implementation date approaches, drawing on the experience in other states
with electric restructuring.
During January 1998, each electric utility would file a bill
unbundling proposal for Commission review. The primary issue likely to
be resolved is the "price" of power (i.e., energy and capacity) as
distinct from other services. The Commission would complete its review by
July 1998, so that utilities would have approximately six months to
complete any needed computer system and procedure modifications.
Utilities' bills would be unbundled beginning January 1999.
VI. ENERGY POLICY AND THE ENVIRONMENT
A. Recommendation
All companies selling electric power to retail customers in
Maine should include a specified minimum amount of renewable energy in
their generation portfolio. Retail providers could fulfill this
requirement with credits that they could buy and sell. The Commission
would consider the market's ability to develop and sell power from
renewable resources, and would establish the renewable portfolio standard.
The Commission would require every retail power seller to report
the mix of fuels used in its generation. The Commission would publish
this information quarterly.
Ratepayers would continue to fund cost effective energy
efficiency programs through revenue collected through the rates of
transmission and distribution (T&D) utilities. The Commission would
establish funding levels, comparable to the levels in 1999 before the
beginning of retail competition, and regularly reevaluate the need and
level. The T&D utility, with Commission oversight, would select the
energy efficiency service providers through periodic competitive bidding.
When retail competition begins, the Commission would cease to
review and certify the construction of generating facilities in Maine and
would no longer oversee plans and planning processes intended to meet the
State's future electric needs.
The Commission supports and will continue to work with other
states and appropriate agencies for air emission standards that minimize
differences between old and new source plants.
Finally, the Legislature should consider directing one or more
state agencies to review the environmental impacts from electric
restructuring and its implication for Maine's energy policy.
B. Discussion
1. Energy Policy and Electricity
The Maine Energy Policy Act (MEPA), the Small Power
Production Act (SPPA), and the Electric Rate Reform Act (ERRA) embody
Maine's electricity-related energy policy. These statutes promote the use
of indigenous and renewable resources, encourage energy efficiency and
conservation, and balance short- and long-term costs and benefits in
meeting Maine's electricity needs. The Commission has carried out these
policies through regulatory orders. For example, the Commission has
pre-approved the utilities' power plant construction and certain types of
power purchases, and has made decisions about power supply and demand-side
resource planning and acquisition.
The Commission's ability to carry out energy policy has
largely depended on the fact that it regulated comprehensively the
provision of electricity. Restructuring would substantially limit this
ability. Beginning in January 2000, customers would choose among power
suppliers; the Commission would not regulate these companies as public
utilities. /41 Thus, the Commission's oversight of electricity-related
decisions would change in both form and degree. Supplier and consumer
choice would replace Commission decisions over what resources will meet
electricity needs, and whether, when and where suppliers build new plants.
The effect of restructuring on energy policy is
significant: decisions about the production and use of electricity
directly impact the environment and the economy. A fundamental
restructuring principle is that it should not diminish the quality of the
environment, compromise energy efficiency, or jeopardize energy security.
Relying abruptly and only on the market to make electricity supply choices
could conflict with that principle. Competitive markets may place more
value on short-term rather than long-term cost savings. And it is
uncertain how the market would value other state policy objectives. This
could lead, absent some intervention, to a power supply that is, in the
long run, less efficient and more costly.
Energy resource decisions, thus, should not initially be
completely relinquished to the market. Although a competitive power
market could benefit customers by lowering prices and increasing options,
its effect on the environment is uncertain. The Commission would
therefore (1) ensure the use and development of generation using renewable
resources; (2) require ratepayers to fund cost-effective energy
efficiency; and (3) ensure the availability of accurate and timely
information so customers can choose power providers based on fuel mix.
Commenters generally supported Maine's energy policy. The
Office of the Public Advocate (OPA), the Industrial Energy Consumer Group
(IECG), Conservation Law Foundation (CLF), American Association of Retired
Persons (AARP), Coalition for Sensible Energy (CSE), Maine's independent
power producers (IPPs) and others supported preserving energy efficiency
and renewable resources. The Paradigm concurred. Residential and small
business consumers in Maine appeared to agree. In a recent Commission
survey, residents and small businesses expressed concerns about the
environment. In New Hampshire's retail competition pilot, companies have
used the fact that their power is environmentally benign to promote sales.
The utilities, by contrast, suggested the market alone
should decide energy resource development and use. In their view,
government involvement in the market to further energy policy goal is
unnecessary and undesirable.
We disagree. The market may bring price and choice
benefits to customers, but its ability to yield a resource mix that
balances other state objectives is unclear. Maine should ensure the use
of renewables and conservation through modest market-based and
market-compatible portfolio and demand-side management (DSM) requirements.
When and if the market delivers a resource mix consistent with energy
policy and environmental goals, the Commission would cease to place
requirements on market participants.
The utilities also argued that placing requirements on
electricity and not on other fuel sources disadvantages electricity
providers. They recommended that any requirement on electricity providers
should apply to all energy sources. The Commission agrees that public
policy should, to the extent possible, avoid burdening one sector of the
market with requirements not imposed on competing sectors. The Commission
does not agree, however, that the solution to any current imbalance is to
abandon all attempts to integrate energy policy with the regulation of
electricity markets.
The utilities argued that Maine cease to regulate
electricity supply and demand choices when retail competition begins. We
disagree, at least in the early years. Restructuring provides a vehicle
to reexamine electricity-related energy policies; however, it does not
itself require or justify their immediate elimination.
2. Renewable Resources in Electric Power Generation
a. Perspective
Nature replenishes renewable energy resources. Several
renewable resources can generate electricity, including biomass or wood,
water, sunlight, and wind. Renewable-fueled generating plants often have
high capital costs, low or zero fuel costs, intermittent output and low
environmental impacts.
Maine's generation mix has a substantial renewable
component. In 1995, hydro-, wood-, and municipal solid waste
(MSW)-generated power provided about 47% of the State's electricity need.
In the same year, hydro, wood, and MSW provided about 10% of New England
Power Pool's (NEPOOL) need. /42 Nationally, renewable plants comprise
about 12% of electric generating capacity.
Federal and state government has encouraged, in a
variety of ways, generation of electricity with renewable resources. One
method used in Maine and elsewhere has been to require utilities to
incorporate renewable resources in their long-term supply planning. Once
the Commission no longer regulates generation, however, this tool will not
be available. The market may, at least initially, disfavor generation
using renewable resources, in part because such facilities tend to have
high start-up costs. To encourage the continued development of renewable
resource generation during at least the initial period of retail
competition, the Commission would require sellers to comply with a
renewable portfolio standard and disclose their fuel mix to customers.
b. Renewable portfolio standard
All companies selling electric power in Maine should
meet part of their customers' needs with renewable power. Companies could
meet this renewable portfolio standard in several ways. They could
generate renewable power. They could buy for resale the output of a
renewable plant. Or, they could obtain renewable credits from companies
that have renewable energy in excess of their portfolio requirement. /43
Companies with entitlements to renewable generation could compete to
provide credits, and all power suppliers could try to minimize the cost of
meeting the standard. If renewable generation becomes competitive with
fossil-fuel generation, the value and the cost of the credits would
decrease. Ultimately, the requirement could be eliminated as the cost of
providing power using renewable resources approaches the cost of other
production methods.
The Commission would adopt the renewable supply
requirement before January 2000. /44 In establishing the requirement,
the Commission would consider renewable provisions in other New England
states, /45 evaluate whether the portfolio requirement remains the best
method for Maine, and identify the effect on rates and the economy. After
2000, the Commission would reevaluate periodically the requirement and its
level.
The renewable portfolio requirement and the credit
trading will ensure the use and development of renewable generation with a
flexible, market-based approach. The Commission could tailor the
requirement to policy objectives, such as targeting a specific form of
generation. By allowing the market, instead of regulators, to decide what
renewable generation options thrive, the portfolio requirement satisfies
the principle that restructuring should not diminish environmental quality
and the principle that where viable markets exist, market mechanisms
should be preferred over regulation.
Many commenters agreed with encouraging the
development and use of power generated by renewable resources and the
renewable portfolio requirement. These parties include the OPA, Maine's
IPPs, and the CSE.
The utilities objected to the renewable portfolio
requirement. They argued that the market ought to decide what resources
meet consumers' electricity needs. They also emphasized that the same
requirements ought to apply to electricity and other end-use fuels. As we
have said, however, we believe the competitive market is unlikely, at
least initially, to act in sufficient conformity to Maine's energy policy.
The Maine Municipal Utilities Group (MMUG) noted that
suppliers could resist disclosing their resource mix or conforming to
standards. As a result, they could be reluctant to enter Maine's market.
However, other states are likely to have renewable provisions; /46 thus,
Maine would be no less attractive than other states. Moreover, before
placing requirements on companies selling power in Maine, the Commission
would ensure that those requirements do not deter competitors from the
Maine market.
CLF supported provisions to ensure environmental
quality and renewable resources. CLF, however, asserted that the
portfolio approach could be burdensome and complex and could impede the
development of renewable technologies. CLF also suggested that potential
litigation over Commerce Clause questions could delay execution of the
portfolio requirement. /47
As an alternative, CLF proposed a wires charge. We
believe a wires charge is inferior to the portfolio requirement. A wires
charge would require more regulatory oversight than the portfolio
requirement, which counters the principle that where viable markets exist,
market mechanisms should be preferred over regulation. Specifically, as
the cost difference between renewable and other forms of power generation
change, the value and cost of meeting the minimum renewable portfolio
standard would self-adjust, and not require regulatory intervention.
Regulators would have to adjust the wires charge to reflect a changed
market. For the portfolio requirement, regulatory action would be limited
to adopting levels, reporting requirements and enforcing compliance.
CLF also argued that the portfolio requirement would
be complex and therefore a burden. It is instructive that a similar
system under the Federal Clean Air Act for SO2 allowance trading works
reasonably well.
c. Resource mix disclosure
Customers should be able to choose electric power
providers based on what resources each provider uses to produce power.
Customers may want to buy from suppliers based on production
characteristics. For example, some customers may want to purchase energy
generated with environmentally benign resources; some may want to exclude
nuclear power, or power produced using coal or hydro. The Commission's
survey on electricity issues suggests that more than 80% of Maine's
residential customers and 75% of small businesses want to know how their
electricity is generated, and a majority places a premium on clean power.
Surveys in other states, such as Texas, reveal similar customer
preferences. Sellers competing in New Hampshire's retail pilot have used
environmental attributes as a marketing strategy.
To provide customers with information to make these
choices, power suppliers should disclose their generation resource mix.
The Commission would publish that information quarterly. The independent
system operator (ISO) could oversee compliance. The ISO would have much
information about production available in the normal course of business.
Commenters unanimously agreed that customers should
have access to accurate information on the resource mix of potential
suppliers. Except for CLF, CMP and MMUG, commenters supported a fuel
disclosure requirement. CLF and CMP identified potential practical
problems with the disclosure requirement and questioned the need. They
asserted it could be difficult or impossible for energy suppliers to
identify and report this information in a way that assists customers. We
believe the benefits of disclosure outweigh the costs. Suppliers ought to
know their resource mix; if they sell spot market power, they could
provide system average mix data. If the market develops other means to
provide credible data, the Commission would eliminate this requirement.
Some commenters suggested suppliers disclose other
information, such as data about emissions and the geographical location of
their power plants. We disagree. Such further disclosures would not
provide sufficient additional useful information to justify the increased
complexity and cost. We expect, however, that additional sources of
information would become available in the marketplace.
3. Efficient Use of Electricity
Conservation and the efficient use of electricity can
deliver value to customers at lower cost and with fewer adverse
environmental impacts than producing more power. Federal and state policy
has encouraged conservation and the efficient use of electricity. Utility
regulators have often carried out these policies. In Maine,
ratepayer-funded DSM has saved over six billion kilowatt-hours. The
Commission required utilities to support DSM because it believed that
customers may view the "payback" for DSM investments as too long;
utilities may resist DSM because they may see their profits fall when
customers save, rather than use, electricity.
The Commission would, at least initially, continue to
ensure that consumers fund these programs through T&D rates. The
Commission would set initial funding at a level comparable to that in
1999, and regularly review the need for funds, and their level. The T&D
utilities, with Commission oversight, would solicit bids periodically to
provide cost-effective efficiency services, select the vendor(s), and
administer the contracts. T&D utilities could bid to provide energy
services, even in their own service area.
Continuing to fund an appropriate level of DSM is
consistent with the principles that restructuring should not diminish
environmental quality, compromise energy efficiency, or jeopardize energy
security. It is at best a possibility, and by no means a certainty, that
markets would immediately yield an abundance of efficiency-related energy
services.
The OPA, CLF, CSE and the IPPs supported requiring
customers to pay for efficiency programs through the T&D utilities' rates,
and endorsed bidding as a way to minimize the cost. Utilities and Madison
Paper Industries do not believe that continued DSM funding through
regulated rates is necessary. They believe the market would deliver
appropriate energy efficiency services. The utilities further argued that
imposing requirements and costs on electricity and not other fuels
distorts markets and unfairly disadvantages providers of electricity. The
Commission agrees that differences in the burdens placed on competitors in
the energy market should be eliminated to the extent possible.
Nevertheless, we are unwilling to entirely abandon regulatory requirements
for conservation and the efficient use of electricity without clear
legislative direction.
CLF and Ed Holt & Associates opined that setting initial
funding at 1999 level would be inadequate. Holt also asserted that
linking funding levels to a future year would give utilities an
opportunity to reduce DSM spending. Holt offered no basis for the
conclusion that regulatory oversight through 1999 would be inadequate to
set DSM spending levels at an appropriate level; we believe that
conclusion is unwarranted.
4. Long Term Resource Planning and Certification of Need
The Commission has executed state energy policy by
regulating the utilities' power purchases and resource planning. Through
its oversight, the Commission has sought to minimize electricity costs
over the long term, encourage the use of indigenous renewable resources
and energy efficiency, and ensure that generation-related decisions were
in the public interest. Beginning in the year 2000, the Commission would
no longer review power plant construction and other power acquisition
decisions. The move to competition, and the accompanying shift of risk to
private investors, would largely replace, and improve upon, regulatory
oversight. However, there may remain matters regarding the construction
and siting of power plants that warrant continuing government oversight.
The Legislature should consider whether the Department of Environmental
Protection or a newly formed entity such as a siting council or energy
office should oversee these issues.
5. Air Quality Impacts of Restructuring
The Commission supports the application of emissions
standards to minimize differences between old and new source generating
plants. Because this matter extends beyond Maine's borders, the
Commission could address it only through working with other states and
Federal agencies. The Commission would not set up different standards for
Maine generating facilities than are imposed on a regional or national
basis.
Older, less efficient, and more polluting coal and oil
plants could have a competitive advantage. These plants tend to have
lower total costs, but higher heat rates and higher emission rates than
newer plants. Many older plants were grandfathered with respect to New
Source Performance Standards of the Clean Air Act (CAA), because at the
time Congress enacted the CAA these plants were expected to retire soon.
As competition develops, these plants may find new markets for their
power, further contributing to delays in their being displaced by newer
plants.
This creates two problems. First, it could exacerbate air
quality problems. Second, the plants would have an unfair competitive
advantage because they are grandfathered, and that could discourage the
emergence of additional power suppliers. Thus, benefits of competition
would lag, and air pollution would increase.
Maine and the rest of the northeast region would be
particularly disadvantaged. The low-cost coal plants in the midwest are
among those most likely to have increased demand for their power. If they
expand their production, levels of NOX, SO2, and CO2 would increase,
potentially degrading Maine's air and water quality, increasing Maine's
cost of complying with the CAA. That would occur whether or not the power
from the midwestern plants is sold into the northeast market.
All commenters agreed the presence of old and new source
plants in the competitive market would create environmental and economic
challenges for the northeast. Except for CLF and Maine's IPPs, parties
agreed that regional or Federal solutions are necessary. They agreed that
Maine ought not impose emission standards on its old source plants that
are more stringent than standards required in other states.
Maine's IPPs recommended applying emission standards to
those who sell power to retail customers. This approach, however, would
be similar to, and perhaps duplicative of, a renewal portfolio standard.
Therefore, imposing such emission standards could discourage companies
from entering the Maine market. CLF proposed Maine require the older,
fossil-fueled utility-owned plants within its borders to conform to
emission standards comparable to those required for new plants, regardless
of what other states do. They asserted this would allow Maine to argue
more effectively for similar requirements in states up wind. We are not
persuaded, however, that Maine acting alone is likely to have any
significant effect on the operation of power plants in the midwest. On
the other hand, such a requirement would further disadvantage Maine power
producers subject to the standards. We prefer, therefore, to continue to
seek regional and national solutions.
C. Further Proceedings
The Commission would begin a proceeding, in early 1998, to
determine the appropriate level of renewable energy generation to be
included in the production mix of all power sellers in Maine, and to
establish the guidelines necessary to implement this renewable portfolio
requirement. The proceeding would be concluded in early 1999.
The issues to be resolved in this proceeding would include the
level of renewables to be required; the extent to which any Maine
requirement should vary significantly from similar requirements (if any)
elsewhere in New England; how renewable "credits" would be calculated and
traded; what price impacts various renewable requirement levels would
have, and the effect of those price impacts on consumers; and whether any
particular level of renewable requirement would produce measurable
benefits for Maine such as reducing the cost of complying with Federal
Clean Air Act standards.
Beginning in mid-1998, the Commission would review the framework
and substance of the demand-side management programs to be administered by
the T&D utilities in the new competitive environment. These reviews would
be concluded by mid-1999.
Issues in these proceedings would include how costs and kWh
savings would be calculated; whether any costs should be deferred, and if
so over what period; whether there should be a limit on the price impact
of DSM programs; and how any costs should be included in rates.
VII. STRANDED COST
A. Recommendation
Electric utilities would have a reasonable opportunity to
recover legitimate, verifiable, and unmitigatable costs stranded as a
result of retail access. A reasonable opportunity is not a guarantee of
cost recovery. Utilities should have only the opportunity for cost
recovery comparable to that under current regulation. The Commission
would not allow utilities to recover costs for which obligations were
incurred after March 1995, unless the associated obligations were
specifically mandated by the Commission or other public authority.
The Commission would require utilities to mitigate those costs
aggressively, and would require utilities to obtain the highest possible
value from their generation assets and contracts. The Commission would
not reconcile stranded costs after-the-fact, but would review them
periodically and, if warranted, adjust them on a going forward basis.
Stranded costs would be collected from customers through the
regulated rates of the transmission and distribution (T&D) utilities. The
Commission would establish the rate design for stranded cost recovery
before the beginning of retail competition. The Commission would not
establish exit fees or similar charges as a part of industry
restructuring.
B. Discussion
1. Nature of Stranded Costs
Certain costs and obligations incurred by utilities to
fulfill their legal obligation to provide electricity may become
unrecoverable, or stranded, when retail competition begins. These costs
fall into three general categories: (1) above-market costs associated with
utility-owned generation plants; (2) above-market costs associated with
generation-related contracts, most notably contracts with qualifying
facilities (QFs); and (3) regulatory assets related to generation such as
those associated with canceled plants and QF contract buyouts. /48 For
the most part, current utility rates include these costs.
Traditional regulation provides utilities a reasonable
opportunity to recover their costs, if prudently incurred, through the
ratemaking process. In a retail market opened to competition, utilities
may be able to recover only market value of their generation assets or
power contracts; any remaining costs /49 associated with these assets in
excess of the market value may be "stranded." A utility asset or contract
could have a market value below or above the utility's remaining cost.
The total stranded cost is the sum of the differences between remaining
cost and market value, both positive and negative, of utility assets and
contracts. Because regulatory assets represent only ratepayer
obligations, they do not have a market value. The total of a utility's
regulatory assets must therefore be added to other stranded costs.
Not all costs that become unrecoverable are "stranded" by
retail competition. Customers may reduce or even eliminate electricity
usage by self-generating, fuel switching, production cutbacks, energy
conservation, and bypassing the utility's system entirely. All these
activities result in fewer revenues available to the utility to pay the
fixed costs of operations. These customer options, however, exist under
current regulation as much as they would after retail competition begins.
/50 The Commission would continue to consider whether the cost-shifting
that may result from these reductions in usage warrants regulatory
intervention.
2. Utility Recovery of Stranded Costs
a. Opportunity for recovery
The Commission would allow utilities a reasonable
opportunity to recover legitimate, verifiable and unmitigatable stranded
costs that result from retail competition. The Commission would design
the rates to recover stranded costs so that the opportunities, risks and
uncertainties for cost recovery would be comparable to those under the
existing regulatory system. Industry restructuring would provide no
additional guarantees or enhanced certainty for stranded cost recovery.
Most commenters supported or did not oppose this approach to stranded cost
recovery.
Historically, utilities have had a legal obligation to
provide adequate and safe service at just and reasonable rates to all
customers within their geographic service territories. These obligations
prevented utilities from refusing to serve any customer, including those
who might impose high costs on the system, and required utilities to have
adequate generation capacity available to meet current and future demand.
The obligation to provide service in return for the right to exclusive
service territories is sometimes called the regulatory compact.
The Maine Law Court has long recognized the underlying
principle of this compact:
The whole body of public utility law has been developed here and
elsewhere upon the concept of regulated monopoly. Implicit in
this concept is an acceptance of the principle that a public
utility offers its facilities and services to the public without
discrimination and that it is obligated to extend its service as
needed within its service area unless the supervisory agency
determines that it is not practicable or economically feasible
to do so. A public utility yields to the sovereign with respect
to approval of rates, methods of financing and other matters of
policy which are ordinarily within the sole province of
management in private business. In return for relinquishing the
right to determine without let or hindrance whom it will serve,
what it will charge, or how it will finance or invest, it is
usually given relative freedom from competition in its service
area on the part of public utilities similarly regulated and
controlled. The monopoly thus afforded as among competing
public utilities is in effect a quid pro quo for the obligation
to render public service and to submit to regulation and
control.
Dickinson v. Maine Public Service Co., 223 A.2d 435, 438 (Me. 1966).
Opening a utility's franchise area to retail
competition would effectively break the existing regulatory compact. The
central issue for stranded cost recovery is whether, after the franchise
for power sales is opened, utilities who invested in power supply to
fulfill their franchise obligations should be given, in the restructured
market, a reasonable opportunity to recover those investments. The
Commission believes that utilities should be given that opportunity. In
essence, utilities should have the same opportunity to recover the costs
in a restructured industry as they had when they incurred the obligations
under an earlier regulatory framework. /51 Moreover, changing the rules
for cost recovery after investments have been made to fulfill service
obligations could impair government's credibility and deter long-term
investment in Maine.
The opportunity to recover costs after retail
competition begins should be equivalent, not superior, to the opportunity
under the current system. Costs incurred imprudently, or costs that are
not mitigated aggressively, have no place in any stranded cost recovery
charge. The Commission would permit stranded cost recovery only to the
extent consistent with strictures of prudent utility management.
One alternative to the recovery principles outlined
above is to reduce the recovery by some specific portion, often described
as "sharing" the burden among utility shareholders and customers. The
Commission does not recommend that approach. Any portion selected could
only be arbitrary and inevitably subject to a legal challenge that could
delay the beginning of retail competition. It would also create
substantial uncertainty in the electric and financial markets. If the
Commission believed that curtailing the opportunity to recover prudently
incurred costs were sound policy, and it does not, it could disallow
recovery under current regulation without the travails of restructuring.
b. Mitigation
To minimize stranded costs, the Commission would
require utilities to pursue all reasonable means to reduce uneconomic
costs and to get the highest possible value for their generation assets
and contracts. /52 The Commission would estimate a reasonable level of
mitigation. Incentives might include price cap regulation, or sharing
savings from cost reductions.
One important opportunity to reduce stranded costs is
in the sale of generation assets. The Commission would rely on the market
to ensure that ratepayers receive the maximum value for those assets. As
the IECG and others observed, the utility should choose the method for any
sale for its ability to obtain the highest possible price. In many cases,
using an auction might produce the best result. In no case would the
Commission rely entirely on a value determined administratively by
calculating the net present value of the cash flow from the current use of
a facility. In the case of a plant currently using oil as fuel, for
example, the market might identify a higher value for the same plant if
that plant were converted to gas. An administrative determination (or
even relying on the sale price offered by an affiliate) in that case would
be likely to understate the value significantly.
In addition, the Commission would continue to require
that the T&D utility, as holder of the QF contracts, explore all
reasonable and lawful opportunities to reduce the cost to ratepayers of
those contracts.
The Office of the Public Advocate (OPA) proposed a
specific incentive to mitigate the costs associated with QF contracts.
The allowance for stranded costs would assume that utilities can achieve a
10% saving in QF contract costs. Utility shareholders would retain
savings in excess of 10%, but would not recover more than 90% of the
original contract costs. We decline now to adopt the OPA's proposal. The
specific incentives for cost mitigation should be addressed
comprehensively in a proceeding. /53
c. Cost recovery limitation
In an order issued in March, 1995, the Commission put
utilities on notice that they would bear the primary market risks of costs
incurred in the future. Order Commencing Rulemaking, Re: Recovery of
Stranded Cost Rulemaking, Docket No. 95-055 at 10 (Feb. 27, 1995); Order
Terminating Rulemaking, Docket No. 95-055 at 3-4 (April 8, 1995). To the
extent generation-related costs incurred after March 1995 become
uneconomic due to retail competition, the Commission would not include any
recovery for those costs in the stranded cost recovery charge.
This limitation does not apply to regulatory assets
created after March 1995, such as amortizations of QF buyout costs, and
costs deferred pursuant to existing rate plans or for conservation. These
regulatory assets result from utility efforts to reduce costs or to
fulfill obligations imposed by the State. Therefore, utilities should
have an opportunity to recover these costs. /54 Similarly, the
limitation does not apply to new obligations over which utilities have no
discretion. For example, Maine Public Service Company (MPS) may have to
extend its contract with Wheelabrator-Sherman. If so, recovery of costs
stranded as a result of the contract extension would not be subject to the
March 1995 cut-off.
Bangor Hydro-Electric Company (BHE) and Eastern Maine
Electric Cooperative (EMEC) opposed any recovery limitation because they
still have an obligation to obtain generation resources to serve ratepayer
demands. We disagree. Beginning in March 1995, utilities in Maine could
no longer claim an expectation of an invulnerable franchise, and
traditional opportunities for cost recovery, extending indefinitely into
the future. Prudent management would, at that point, understand that
potentially uneconomic burdens would be at their shareowners' risk. /55
d. Constitutional authority
Central Maine Power Company (CMP) argued that, as a
matter of law, states must allow utilities to recover any and all stranded
costs. It rests the argument on restrictions against governmental takings
of property in the United States and Maine Constitutions. We do not agree
that the Constitution so rigidly constrains the Commission's discretion.
A commission may decline to allow the recovery of
costs, even prudently incurred costs, without exceeding constitutional
limits unless the result is confiscation of the utility's property, taken
as a whole. Such confiscation will be found only where the utility's
financial integrity is seriously jeopardized. Duquesne Light Co. v.
Barasch, 448 U.S. 299 (1989).
Indeed, regulatory decisions that injure the utility's
financial integrity may be lawful. For example, a state can continue to
apply longstanding ratemaking principles even if it results in substantial
financial harm or bankruptcy. Appeal of Public Service of New Hampshire,
547 A.2d 269 (N.H. 1988). If management imprudence compromises a
utility's financial integrity, regulators are not constitutionally
compelled to rescue its shareowners.
The Commission's conclusion that utilities should be
allowed a reasonable opportunity to recover costs stranded by retail
competition does not, therefore, rest solely upon constitutional
principles. It rests also on the Commission's belief that government and
citizens are best served when decisions are made in a fair and consistent
manner.
3. Determination of Stranded Cost Charges
a. Process
The Commission would estimate stranded costs for each
electric utility. It would then use the estimates to develop the stranded
cost rates to be charged by each T&D utility when retail competition
begins. To reduce the risk of establishing rates that are grossly too
high or too low, the Commission would, at a minimum, reexamine the
stranded cost rates and correct for substantial inaccuracies in 2003 and
again in 2006.
To determine the market value of generation-related
assets and contracts, the Commission would rely to the greatest extent
possible on market information. The Commission would consider factors
including, but not limited to: market valuations that become known as
plants and the rights to power from QF contract are sold, current and
likely future regional market prices for power, and stranded cost
determinations in other New England states.
The National Independent Energy Producers suggested
that a competitive sale should determine an asset's market value. The
Paradigm supported an auction approach. We agree that, to the extent
possible, it is best to use market techniques to identify value. We
depart only to the extent that we believe flexibility, instead of limits,
on which market techniques T&D utilities use is likely to maximize the
value of assets.
While CMP and BHE would be required to divest their
generation assets no later than January 2006, utilities could propose to
divest earlier. In the event a utility divests all or a significant
amount of its assets prior to 2006, the Commission would review and, if
warranted, modify that utility's stranded cost rates. When the utility
completes the divestiture or sale, the Commission would finally decide the
stranded costs associated with the asset. When the T&D utility no longer
owns a power-producing asset, fluctuations in the value of that asset
cannot be readily reflected in rates charged by the T&D utility. If the
value of the asset increases, which would in theory reduce stranded costs,
there is little chance of persuading the new owner to raise the price it
already paid for the asset. If the value decreases, neither the T&D
utility nor its ratepayers should be forced to help the unlucky buyer.
Any "final" stranded cost determination for divested
assets creates a risk of inaccurate stranded cost charges if market values
change. This risk would be reduced, to some extent, by the Commission's
reexamining periodically the stranded cost associated with QF contracts
and Maine Yankee. Because QF contracts and Maine Yankee ownership would
remain with the T&D utilities, the Commission could review and modify
associated stranded cost estimates at any time, including after 2006,
until each of the contracts terminates and Maine Yankee ceases to operate.
This should help to ensure stranded cost charges remain reasonable.
Moreover, the total amount of stranded costs will decrease with the
passage of time; mis-estimation of market value in 2005 or 2010 will
necessarily have a smaller impact than mis-estimation in 1998 or 2000.
The Commission would adjust stranded cost charges on a
prospective basis and not reconcile or true-up amounts to reflect past
"actual" values. The purpose of periodic reviews is only to correct
substantial estimation inaccuracies, not to guarantee dollar-for-dollar
recovery or to reflect minor fluctuations in market value.
BHE and MPS supported a dollar-for-dollar
reconciliation of stranded costs to account for any inaccuracy in
estimates. However, such an approach could weaken incentives to mitigate
stranded costs. With reconciliation, utilities would be financially
indifferent with respect to mitigation. The regulatory lag created by a
system of forward-looking rate adjustments has the additional benefit of
giving T&D utilities a stake in the success of the competitive power
market. A lower market price for power should stimulate T&D sales and, to
the extent the stranded cost charge is based on usage, increase the T&D
companies' revenues and profits. This stake would be lost, however, if
past collections were somehow "reconciled."
b. Methodology
For utility-owned power plants, the Commission would
estimate stranded costs by calculating the difference between net plant
investment and the value of expected future profits. For purchased power
contracts, it would calculate the difference between future contract
payments and the market value of the power. /56 The stranded cost for
each asset or contract could be positive or negative depending on whether
the market value is less or greater than the remaining cost.
Another approach to calculating stranded costs,
sometimes called the "revenues lost" approach, simply subtracts the costs
the utility saved by the departure of a customer lost to a competitor from
the revenues lost. /57 This methodology may be useful in certain
circumstances, such as where an entire municipality leaves the utility's
system. Conceptually, however, there is a closer match between uneconomic
costs of generation and the introduction of competition in the retail
generation market. For that reason, the Commission prefers to focus on
generation-related assets.
The Commission's range of stranded cost estimates
together with a more detailed discussion of methods is contained in
Appendix 5.
4. Recovery Mechanisms and Rate Design
The stranded cost liability associated with retail
competition would lie with the T&D utilities and be recovered in regulated
rates. Stranded costs result from obligations incurred by regulated
utilities, and it is appropriate that they be recovered from the
ratepayers of regulated entities. If stranded costs were recovered by
unregulated power providers, those companies would have advantages and
burdens neither available to nor imposed upon competitors. For example,
if a generation company receives stranded cost payments, it would have an
identifiable revenue stream that could provide cash flow advantages.
The Commission would design rates to recover stranded costs
for each utility prior to retail competition. All customers using the
services of the T&D utility would pay stranded cost charges. Because
customers that buy power in a competitive market could be expected to buy
the same amount of power they did from the utility before retail
competition, it may be appropriate to impose a usage-sensitive rate for
stranded costs. The Paradigm favored this approach. However, stranded
costs rates should also be designed to satisfy other goals, such as
economic efficiency, equity, rate stability, and should encourage choice
among competitors based on their economic costs. Accordingly, the
Commission would explore rate designs that are less usage sensitive, such
as per maximum kW charges or flat access charges. To establish rate
designs, the Commission would consider the amount to be recovered, the
period over which recovery will occur, and rate designs adopted in other
jurisdictions.
CMP proposed that the Commission allow CMP to impose limits
on customers' opportunity to avoid paying their fair share of stranded
costs. Non-utility commenters generally opposed exit fees. The Commission
does not believe exit fees are either practical or appropriate.
Proponents of exit fees claimed that the demand for electricity of
particular customers has caused utilities to incur certain costs on their
behalf, and that these same customers should pay these costs. This claim
is doubtful. Power purchases are rarely customer-specific. Moreover, if
the idea is to match cost-recovery with cost-causation, some daunting
questions emerge. Should customers have to be on the system any
particular length of time before any exit fee would apply? Should
customers who entered the system last year be required to pay an exit fee
if they leave the system next year? If so, should the amount of the exit
fee be the same as for a customer that has been on the system for 30
years? Should exit fees apply to customers that enter the system in the
future? None of these questions has a felicitous answer.
Exit fees could also adversely affect Maine's business
climate. If exit fees applied to businesses who were utility customers on
a specific date, only newer businesses could switch power suppliers
without paying an exit fee. If exit fees applied to new customers, it
could dissuade businesses from entering the State. What business would
move to Maine if its flexibility to move in the future were so
constrained?
Exit fees are an extraordinary remedy. That approach might
be justified where its absence would result in either extreme financial
stress on the utility or unacceptable rate increases for utility
ratepayers. /58 An exit fee or similar rate design should not be
adopted without a substantial demonstration of ratepayer harm.
C. Further Proceedings
The Commission would establish initial estimates of stranded
costs prior to 2000, using market information to the greatest extent
possible. The Commission would also establish the rates that each T&D
utility would be allowed to charge to recover the stranded costs subject
to recovery. These proceedings are likely to be complex, both with
respect to the proper calculation of stranded costs, and the rate design
appropriate for their collection. Because an important component of the
calculation of stranded costs is the market price for power, the
Commission would conduct further proceedings after 2000 to update the
stranded cost charges based on then current market conditions. In
addition, there would be a link between this case and the bidding process
for QF contracts, because the results of that process would have an effect
on the level of stranded costs.
Some of the issues to be determined in these proceedings are
whether sufficient efforts have been undertaken to mitigate stranded
costs; the estimation of the future market price for power; the proper
level of stranded cost recovery for each customer class; and the specific
rate design for the stranded cost recovery charge.
Because the factors influencing the size of stranded costs are
unique to each utility, the Commission would conduct separate proceedings
for each investor- and consumer-owned utility. Under the Commission's
Implementation Schedule, a nine-month proceeding for CMP would begin in
late 1997, with the proceedings for BHE and MPS beginning in January 1998
and April 1998, respectively. The proceedings for the consumer-owned
utilities would likely be less complex and would begin in April 1998. To
ensure that rates reflect the most up-to-date information and analyses
available, concurrent limited reviews may be needed between April and
December 1999 for each of the utilities.
VIII.REGIONAL ISSUES
A. Recommendation
Maine cannot resolve all issues that will determine whether
retail competition will succeed. Some issues must be addressed on a
regional level or before the Federal Energy Regulatory Commission (FERC).
Regional issues include the reliability of the bulk power and transmission
systems, and the fair and efficient operation of the power market. The
Commission, together with the New England Conference of Public Utility
Commissioners (NECPUC), the New England Governor's Conference (NEGC) and
others, would continue to work to resolve these issues.
Issues that affect Maine's ability to benefit from competition
include governance reform of the New England Power Pool (NEPOOL) to allow
fair and meaningful representation for all market participants; the
existence of an Independent System Operator (ISO) for the transmission
system that would be effectively independent and have no financial
interest in any market participants; the creation and operation of a
voluntary power exchange, either as an independent entity or as part of a
reformed NEPOOL; and rules to ensure that providers meet the North
American Electric Reliability Council (NERC) reliability standards.
B. Discussion
1. Perspective
FERC and state regulatory commissions regulate different
aspects of electric transmission. FERC has authority over rates charged
for interstate transmission and limited authority over reliability. /59
State commissions have authority over transmission facility siting within
the state, and jurisdiction over retail rates. /60 This jurisdictional
overlap creates challenges for restructuring, particularly in regions with
tightly integrated, multi-state power systems. In New England, facilities
owned by many different companies and located in six different states
operate as a single system. NEPOOL coordinates and operates the system.
Facility owners participate voluntarily in NEPOOL, and FERC oversees its
governing agreements. Thus, a single state cannot mandate changes to the
New England system necessary to accommodate competition.
In the New England region, power is regularly bought and
sold in a wholesale market. The rules of NEPOOL, for the most part,
govern this market. NEPOOL, which comprises more than 100 utilities in
the region, has major responsibilities for planning and operating the
region's generation and transmission facilities to ensure load is served
reliably and economically. NEPOOL is organized and operates according to
an agreement of the member companies, and is under FERC jurisdiction.
Historically, NEPOOL's membership has been limited to utilities, and the
largest utility members dominate its control.
State Commissions have two formal ways to influence NEPOOL:
state regulation of the member companies within each state's jurisdiction
and participation in FERC proceedings either individually or with other
New England Commissions. The Commission can also communicate its views
about regional issues to NEPOOL in less formal ways. The Commission would
continue to pursue a variety of means to help bring satisfactory
resolution of regional issues. Specifically, the Commission would
continue to participate through informal and, if necessary, formal
intervention at FERC, to reform NEPOOL, to form an ISO, and to develop a
regional transmission group (RTG). As the restructuring proceeds in New
England and elsewhere, the Commission would continue to be involved in
regional issues to the extent consistent with Maine's interests.
2. Reliability
Maintaining the reliability of the electric power system is
critically important. Restructuring should not be allowed to result in
degradation of the regional power system's reliability. The current
industry standard for bulk power system reliability, set by the NERC,
provides that there should be no more than one day in 10 years that load
cannot be served because of inadequate transmission or generation
resources.
Traditionally, utilities in the region have cooperated to
maintain system reliability. Utilities have shared information including
expected load growth, system constraints, and construction plans. The
vertical monopoly structure of the industry has aided this cooperation.
In a competitive environment, companies may be less forthcoming with
information. This could make maintaining sufficient reliability more
difficult. The Commission would work to ensure that regional structures
exist and have the authority to ensure system reliability. All
competitors providing power to Maine customers would conform to
appropriate regional and national reliability standards.
Commenters supported measures to ensure reliability of the
region's power system. The Paradigm included regional reliability
requirements. /61 Central Maine Power Company (CMP) suggested
reliability could be more easily maintained if bilateral contracts were
purely financial instruments and had no impact on system operation.
Further, CMP asked the Commission to specify reliability standards that
competitive providers in Maine would have to meet.
The Commission should not dictate particular reliability
standards. CMP's concerns are best addressed through a reformed NEPOOL and
an effective ISO, and through the requirement that all power providers who
sell to Maine's consumers would have to conform to appropriate regional
reliability standards.
3. Governance Issues in NEPOOL Reform
An essential feature for any entity that controls or
coordinates regional market operation is meaningful and fair
representation of all market participants. The recently expanded NEPOOL
membership indicated the intent to file documents with FERC that would
reform NEPOOL to accommodate a more competitive and open generation
market, and to allow non-utility interests a voice within NEPOOL regarding
how the market operates. The Commission has participated in and monitored
the progress of NEPOOL restructuring discussions and will continue to work
toward a system that provides appropriate representation for all market
participants.
4. The Independent System Operator
The region's integrated bulk power and transmission systems
require an operator to ensure the coordination of generation and load. In
New England, the system operator oversees the generation and transmission
resources of all companies within NEPOOL to ensure reliability and to
minimize the costs of serving the aggregate pool load. Currently, the New
England Power Exchange (NEPEX), an arm of NEPOOL, performs this function.
To the extent system operation is linked directly to the financial
interests of market participants, as it is now, the tasks may not be
performed in a competitively neutral manner.
Therefore, the Commission supports creating an ISO with no
financial interest in the success or failure of any particular market
participant, or group of participants. It would continue to work toward
that end. Commenters generally supported the ISO concept, but differed
about the degree and form of independence necessary. The Paradigm
included provisions for an ISO that would have no financial relationship
to energy providers. The Commission would continue to work toward the
creation of a truly independent ISO.
5. Transmission Pricing and Access
A healthy competitive market for generation depends on the
availability of transmission services at non-discriminatory terms and
prices. The FERC has made clear its requirements in this regard. There
are ongoing efforts to establish the framework and rules for a RTG in New
England to carry out FERC's mandates. The Commission has been and will
continue to participate in these efforts and, if necessary, in related
FERC proceedings.
Because there are separately owned transmission systems
over which power flows in New England, there are difficult issues
regarding how the region's transmission services should be administered
and priced. As a general matter, prices for transmission should recover
the transmission provider's cost of service and encourage the efficient
use and expansion of the regional bulk power system. Existing pricing
systems that discriminate or artificially favor the purchase of power from
one generation unit above another (e.g., Pool Transmission Facility (PTF)
rates) /62 should be eliminated over time. The Commission would continue
to work to ensure that the rules and prices governing transmission in the
region are consistent with fair and efficient market competition, and do
not unduly disadvantage sellers or buyers in Maine.
Commenters generally agreed that transmission access and
pricing must be open, fair, and efficient. The Paradigm reflected these
same principles. Bangor Hydro-Electric Company (BHE) suggested the
Commission not promote eliminating the PTF rate until a new method of
pricing exists that ensures open access to regional transmission
facilities at reasonable rates. According to BHE, eliminating PTF rates
without reasonably priced open access transmission would limit competition
and create opportunities for market power. The Commission expects the
elimination of PTF-type rates would occur in the context of the RTG.
Thus, the pool-wide rates and terms reflected in the RTG would replace PTF
rates and, in principle, ensure fair and equal access to regional
transmission. It may also be appropriate to phase-out PTF arrangements
gradually to facilitate agreement on an RTG and minimize near-term
disruptions for BHE and similarly situated utilities.
6. The Power Exchange
Certain structures can help market operations and provide
participants with information to make informed and economic choices. In
the emerging electric power markets, a regional power exchange could
perform these functions. The power exchange would be a spot market,
allowing for market transactions in real time without the need for
specific contracts between individual buyers and sellers. The exchange
would receive and rank power supply bids, and determine and post market
clearing prices. Participation in the exchange would be voluntary. Other
power exchanges or similar mechanisms could evolve and coexist with or
replace this exchange. The power exchange could be part of the same
organization that provides the ISO services, though some have advanced
theoretical arguments supporting a fully separate organization.
Enron Capital and Trade Resources (Enron) asserted there is
no reason to create a power exchange. According to Enron, open
transmission access and unbundled rates, together with the interplay of
buyers, sellers, and merchants would achieve an effective and efficient
market. In addition, Enron argued that the creation of a power exchange
could hamper the development of a forward market. However, if
established, Enron argued the exchange must be independent of the ISO and
cease to exist by a certain date.
The Commission believes a power exchange is likely to
perform an important role in the development of effective competition.
If, as Enron asserted, the power exchange is unnecessary or uneconomic,
buyers and sellers would use it little, or not at all. Thus, if Enron is
correct, the market itself would eliminate the exchange. If it is
voluntary, a power exchange should not hinder other transactions nor
preclude the development of forward markets if such markets are efficient.
7. Horizontal Market Power Study
There is a risk that some market participants may control a
large enough share of the region's power supply to allow them to exert
undue influence over market prices. In that event, the benefits of
restructuring would not flow to consumers.
To the extent possible, opportunities for market power
should be minimized before retail competition. After-the-fact anti-trust
enforcement would be expensive and likely ineffective, because the
unlawful exercise of market power is difficult to detect and even more
difficult to prove. The Commission recommends that the Legislature direct
state agencies, including the Commission, to study regional power market
and recommend steps to minimize market power opportunities before the date
of retail access.
C. Further Proceedings
The Commission would continue its efforts at the regional level
and, if needed, at FERC to resolve regional restructuring issues. The
Commission does not currently anticipate proceedings before the Maine
Commission to resolve the matters discussed in this section.
End Notes
/ 1 Throughout this Report, we have used the terms "generation
service" and "power" as synonyms. In this document, these terms
refer to the provision of electric power as distinct from
transmission and distribution services (i.e., the wires and
other facilities needed to transport the power, and access to
those facilities). "Generation providers" refer to generators,
marketers, brokers, aggregators, or any other entity producing
or selling electric power.
/ 2 The Maine Commission was the first to adopt comprehensive price
cap regulation for electric utilities. The approach is common
in the telephone utility industry.
/ 3 Cogeneration refers to the use of excess thermal energy,
generally produced as a result of manufacturing processes, to
generate electricity. Small power production relies on
renewable resources such as hydro and biomass as the primary
source of fuel.
/ 4 These filings are currently under review by FERC.
/ 5 Regional matters are discussed in Section VII, below.
/ 6 NEPOOL currently projects that the regional surplus of
generating capacity will end in approximately 2000. As
surpluses in generating capacity diminish, the price for
electric power at the wholesale level is likely to increase.
/ 7 There may be components of distribution service (e.g., metering)
that could be unbundled and provided by competitive markets.
Our plan neither proposes nor precludes any such unbundling of
distribution services in the future.
/ 8 As a matter of physics, electricity generated by or for a retail
provider is not actually consumed by its retail customer.
Instead, all generators in the region place electric power on
the grid that is simultaneously consumed by all end use
customers on the system. As a result, retail competition only
allows for financial transactions involving the obligation of
providers to place specified amounts of electric power on the
regional system to meet the demands of their retail customers.
/ 9 This matter is discussed in section VIII, below.
/10 Customers that do not choose a competitive generation provider
would take service under the standard offer. This service is
discussed in section IV, below.
/11 To the extent a separate or unbundled retail transmission rate
is established, FERC has indicated that it has jurisdiction to
determine the rate. FERC Order No. 888 (April 24, 1996).
/12 As the industry is restructured, some amount of additional price
volatility can be expected as a natural consequence of moving
away from a regulated environment. Customers should, however,
have tools available to them to limit that volatility, much as
purchasers of home heating oil do today.
/13 The introduction of retail competition will create winners and
losers among generation providers. There are likely to be
mergers and consolidations as companies seek the best ways to be
competitive. As a result, the current mix of "local" and
"regional" producers serving the Maine market is likely to
change. This is a natural consequence of allowing competition
in retail generation markets.
/14 Stranded costs are discussed in section VII, below.
/15 Traditionally, research and development (R&D) of generation
technologies occurred, to a large extent, through the Electric
Power Research Institute (EPRI), an organization funded by
utilities and their ratepayers. With the deregulation of
generation, EPRI is likely to reduce or eliminate generation
R&D. The extent to which unregulated entities will devote
resources to generation R&D is unknown.
/16 Areas such as the South and Northwest have relatively lower
rates due in part to federally subsidized hydro-electric
projects (e.g., Tennessee Valley Authority, Bonneville Power
Administration) and the close proximity of relatively
inexpensive coal, oil, and natural gas.
/17 In Maine, the change in incentives should not be dramatic,
because under the regulatory method and commitments already in
place for Central Maine Power Company, Maine Public Service
Company, and Bangor Hydro-Electric Company, changes in tax
assessments already flow almost entirely to shareowners rather
than ratepayers.
/18 For example, the Massachusetts Legislature considered a bill to
compensate municipalities for any loss in property tax revenue
that may result from a devaluation of electric generation
facilities due to the restructuring of the electric industry.
The Massachusetts Legislature has not taken any final action on
the bill.
/19 The Commission would have the authority to delay or accelerate
the beginning of retail competition by up to 90 days if
necessary for administrative or technological reasons. A change
in the start date by more than 90 days would require legislative
action.
/20 In this document, the "Paradigm" refers to the "Paradigm for
Restructuring Investor-Owned Electric Utilities: A New Industry
Structure," a restructuring plan that was supported by eight
members of the Work Group on Electric Industry Restructuring.
The eight members of the Work Group that presented the Paradigm
are: American Association of Retired Persons, Senator John
Cleveland, Conservation Law Foundation, Independent Energy
Consumers Group, Independent Energy Producers, Representative
Carol Kontos, Office of the Public Advocate, and Pine Tree
Legal.
/21 These states are Rhode Island, New Hampshire, Massachusetts, and
Vermont.
/22 These matters are discussed in more detail in section VII,
below.
/23 Such litigation appears likely in New Hampshire.
/24 Customer education efforts are discussed in section V, below.
/25 The efficiencies and innovations that should result from retail
competition will develop over time. The shifting of costs from
ratepayers to shareholders or among ratepayer groups is in no
sense an "efficiency gain" from competition. It is simply a
transfer of dollars.
/26 Customers in a town could choose alternate suppliers even if a
municipality decides to aggregate load on behalf of its
residents. A municipality would have to seek legislative
authorization to restrict consumer choice.
/27 The cost of special meters has been dropping in recent years and
is likely to continue to do so. Applied Resources Group stated
in their comments that reasonably priced load profile meters are
likely to be available by 1998. BHE suggested that necessary
meters entail a substantial cost, while the Maine Municipal
Utilities Group (MMUG) stated that the necessary technology does
not exist unless load is aggregated on a geographic basis.
/28 Once generation services are no longer subject to price
regulation, any currently-existing immunity from the anti-trust
laws would effectively disappear.
/29 Some have raised questions regarding the impact of the North
American Free Trade Agreement (NAFTA) on reciprocity issues and
access by Maine providers to Canadian markets. Basically, NAFTA
provides for equal treatment of United States and Canadian
producers. For example, if it were lawful for Maine to have a
retail access reciprocity requirement, the requirement could be
applied to Canadian providers.
/30 Maine's IOUs are CMP, BHE and MPS.
/31 COUs are municipal or quasi-municipal electric utilities and
electric cooperatives.
/32 When referring to the period after December 1999, the terms
"CMP" and "BHE" refer to those two companies' continuing T&D
utility entities.
/33 T&D utilities may develop services which are largely unrelated
to their core regulated activities. In such cases the T&D
utility would have no obligation to offer such non-core and non-
regulated services to all customers or energy providers.
/34 For an analysis of the State's authority to order divestiture,
see Responsive Comments of OPA, filed on September 13, 1996 in
Docket No. 95-462.
/35 For further discussion of this issue, see Section VII(B)(3)(a).
/36 In prior years, the Commission determined electric utility
avoided costs in blocks of capacity referred to as "decrements."
The utilities then went out to bid for blocks of power from
independent producers, primarily QFs, for each decrement capped
at the avoided cost.
/37 To the extent such information has value and is transferred to a
utility affiliate or sold for a profit, the value should accrue
to ratepayers.
/38 A counter-factual analysis attempts to isolate the economic
effects of a policy change during a time period and compare them
to the economic effects that an alternative policy would have
had during the same time period. For example, it is often
impossible to separate the impact of one policy change from
contemporaneous changes in other factors. Moreover, it is
difficult to estimate what the status quo would have been absent
the policy change. These difficulties would be especially
apparent in electric restructuring due to the many policy
changes embodied in the effort.
/39 This could occur if customers continually take service from the
market when conditions are favorable and then switched to the
standard offer when market conditions change.
/40 The Commission's Rules for credit, collection and disconnection
are currently contained in Chapters 81 and 86. The Commission
anticipates re-examining these Chapters and may modify their
provisions.
/41 The commission would continue to regulate standard offer service
providers to some extent.
/42 These numbers do not include self-generated electricity, nor
NEPOOL net interchanges.
/43 A market may develop for renewable credits, similar to that for
trading of sulfur dioxide (SO2) allowances under the Federal
Clean Air Act.
/44 The Commission would also determine in the proceeding what
energy sources would be considered "renewable".
/45 The Vermont Public Service Board recently proposed a portfolio
requirement with tradable credits as part of its recommendations
for restructuring.
/46 New Hampshire, Massachusetts, Vermont, and Rhode Island appear
likely to include provisions to ensure renewable resource
generation. California provides funding for renewable
technologies.
/47 The Commission's view is that a renewable portfolio standard
would not violate the Commerce Clause.
/48 Regulatory assets are not tangible, physical assets. They are
essentially ratepayer obligations created by regulation. These
assets represent costs that utilities have incurred in the past,
but are recovered from ratepayers over time.
/49 Under traditional ratemaking, the cost of generation assets are
recovered through the utility's rate base over their depreciable
lives. The remaining costs of these assets are those that have
not yet been recovered. The costs of purchased power contracts
have generally been recovered as an expense. The remaining
costs of these contracts refer to the payments for future
deliveries of power under the terms of the contracts.
/50 The United States Supreme Court has recognized a Constitutional
distinction between a reduction in economic value that results
from governmental action as opposed to general economic forces.
Market St. Ry. Co. v. Calif. R.R. Comm'n, 324 U.S. 548, 567
(1945).
/51 While not directly applicable, the recent United States Supreme
Court decision in United States v. Winstar Corp., ___ U.S.___,
116 S.Ct. 2432, 135 L.Ed 2nd 964 (1996) suggests, at least, that
government should act responsibly in changing the "rules of the
game".
/52 The Commission does not, however, encourage bankruptcy,
strategic or otherwise, as a tool to reduce costs.
/53 Two jurisdictions, California and Pennsylvania, have enacted
legislation that attempts to mitigate stranded costs, and thus
reduce rates, through innovative financing mechanisms.
Essentially, these jurisdictions have created a statutory right
for the recovery of some types of costs through utility rates.
This results in greater certainty of cost recovery that should
lower the utilities' financing costs. The savings in financing
cost would be passed onto ratepayers.
/54 Consistent with Statement of Financial Accounting Standards No.
71, the Commission would establish rates that specifically allow
for recovery of regulatory assets.
/55 In fact, BHE management appears to recognize this risk in its
power purchases. It has bought relatively short-term power and
has also begun hedging against the risk of fuel price
volatility.
/56 All calculations would reflect present value where appropriate.
/57 FERC has asserted jurisdiction over stranded cost recovery
associated with wholesale service and the formation of new
retail utilities, such as municipalizations. FERC Order No. 888
(April 24, 1996). FERC has indicated that it will use the lost
revenue approach to calculating stranded costs. Because of
FERC's assertion of jurisdiction, the recommended plan does not
address stranded cost recovery with respect to pre-existing
wholesale arrangements or the creation of new retail utilities.
/58 For example, the Massachusetts Commission imposed an exit fee
for a large customer to avoid a significant impact on the
utility and its remaining ratepayers. Re: Cambridge Electric
Light Co., 164 PUR 4th 69 (Sept. 28, 1995). The California
Legislature has authorized changes to customers that bypass
their utility's system as part of a comprehensive restructuring
plan that includes innovative financing to obtain rate
decreases for all to customers.
/59 Under section 202(c) of the Federal Power Act, FERC may require
utility actions related to reliability if it determines that an
emergency exists.
/60 FERC has indicated that it has jurisdiction to determine the
rates for separated or unbundled retail transmission service.
FERC Order No. 888 (April 24, 1996).
/61 In a survey recently conducted for the Commission, Maine's
residential and small business customers identified reliability
as the most important aspect of electric power.
/62 The PTF rate was established by NEPOOL members to encourage
joint ownership in large generating units distributed around the
region.
Exhibit 99(o)
Page 1 Appendix 2
Proposed Restructuring Legislation
This appendix contains proposed legislation to implement the
Commission's Report and Recommended Plan on Electric Utility Industry
Restructuring issued on December 31, 1996.
This proposed legislation is intentionally less specific than the
Restructuring Report. As is discussed in detail in the Report, the full
implementation of the Commission's recommendations is contingent on a
variety of circumstances and developments. The proposed legislation is
drafted in a way that, if enacted, would specify the limits of the
Commission's authority to implement the restructuring plan while
simultaneously providing sufficient flexibility to accommodate evolving
circumstances that may arise during the implementation of the Plan.
This proposed legislation is not the only legislation that will
ultimately be needed to restructure Maine's electric utility industry.
This proposed legislation would only allow the Commission to begin the
transition to retail competition. Many additional changes to Title 35-A
and other titles in Maine statutes will have to be made before the process
can be completed. At each step of the process, the Legislature will have
the opportunity to review how events are unfolding and determine the
proper next steps.
The Commission recognizes that the legislative role of setting the
proper balance between allowing the flexibility essential to any effective
regulatory process and articulating clear policy is especially complex
where comprehensive change is proposed. The Commission is committed to
assisting the Legislature in any way it can to find that balance for the
future of electricity regulation in Maine.
Page 2 Appendix 2
Proposed Restructuring Legislation
AN ACT to Restructure Maine's Electric Industry
Sec. 1. 35-A M.R.S.A. ch. *** is enacted to read:
CHAPTER ***
ELECTRIC RESTRUCTURING
SS 1. Findings and purpose.
1. Findings. The Legislature finds that:
A. Where viable markets exist, market mechanisms should be
preferred over regulation, and the risk of business decisions
should fall on investors rather than consumers;
B. Customers' needs and preferences should be met with the lowest
costs;
C. All customers should have a reasonable opportunity to
benefit from a restructured electric industry;
D. Electric industry restructuring should not diminish
environmental quality, compromise energy efficiency or jeopardize
energy security;
E. All customers should have access to reliable, safe and
reasonably priced electric service;
F. Electric industry restructuring should not diminish low-
income assistance or other consumer protections;
G. The electric industry structure should be lawful,
understandable to the public, and fair and perceived to be fair;
and
H. Electric industry restructuring should improve the state's
business climate.
Page 3 Appendix 2
2. Purpose. The purposes of this chapter are:
A. To promote efficient and effective competition in the market
for the generation and sale of electricity in the state;
B. To ensure that all consumers of electricity are able to
benefit from competition;
C. To provide an orderly transition from the current form of
regulation to retail competition for electricity;
D. To continue to provide the public with opportunities to
participate in decisions concerning electric restructuring; and
E. To ensure that the commission has all necessary authority to
implement an electric restructuring plan consistent with the
findings and purposes expressed in this chapter.
SS 2. Definitions
As used in this chapter, unless the context otherwise indicates,
the following terms have the following meanings.
1 . Affiliated interest. "Affiliated interest" has the same
meaning as provided in section 707(l)(A).
2. Competitive generation provider. "Competitive generation
provider" means generators, marketers, brokers, aggregators or any other
entity producing or selling electric power to meet retail customers'
demand.
3. Consumer owned transmission and distribution utility.
"Consumer owned transmission and distributed utility" means any
transmission and distribution utility which is wholly owned by its
consumers, including, but not limited to:
A. The transmission and distribution portion of any rural
electrification cooperative organized under chapter 37;
B. The transmission and distribution portion of any
electrification cooperative organized on a cooperative plan under
the laws of the state;
C. Any municipal or quasi-municipal transmission and
distribution utility;
Page 4 Appendix 2
D. The transmission and distribution portion of any municipal or
quasi-municipal entity providing generation and other services; and
E. Any transmission and distribution utility wholly owned by a
municipality.
4. Divest. "Divest" means to legally transfer ownership and
control to an entity that is not an affiliated interest.
5. Large investor owned transmission and distribution utility.
"Large investor owned transmission and distribution utility" means an
investor owned transmission and distribution utility serving more than
50,000 retail customers.
6. Qualifying facility. "Qualifying facility" has the same meaning
as provided in section 3303.
7. Retail access. "Retail access" means the right of any retail
consumer of electricity to purchase generation services from a competitive
generation provider.
8. Small investor owned transmission and distribution utility.
"Small investor owned transmission and distribution utility" means an
investor owned transmission and distribution utility serving 50,000 or
fewer retail customers.
9. Transmission and distribution plant. "Transmission and
distribution plant" includes all real estate, fixtures and personal
property owned, controlled, operated or managed in connection with or to
facilitate the transmission, distribution or delivery of electricity for
light, heat or power, for public use, and all conduits, ducts or other
devices, materials, apparatus or property for containing, holding or
carrying conductors used or to be used for the transmission or
distribution of electricity for light, heat or power for public use.
10. Transmission and distribution utility. "Transmission and
distribution utility" includes every person, its lessees, trustees,
receivers or trustees appointed by any court owning, controlling,
operating or managing any transmission and distribution plant.
Page 5 Appendix 2
SS 3. Retail access
1. Right to purchase generation service. Beginning on January 1,
2000, all consumers of electricity have the right to purchase generation
service directly from competitive generation providers. The commission may
advance or delay the date for retail access by not more than 90 days if
necessary to achieve the purposes of this chapter.
2. Aggregation permitted. When retail access begins, all
consumers of electricity may aggregate their purchases of generation
services in any manner they choose.
3. Public agency may not restrict choice. If a public agency
serves as an aggregator, it may not require consumers of electricity
within its jurisdiction to purchase generation services from that agency.
SS 4. Deregulation of generation services
Except as otherwise provided in this chapter, competitive
generation providers are not subject to regulation under this Title as of
January 1, 2000.
SS 5. Structural separation and divestiture of generation
1. Structural separation required. On or before January 1, 2000,
each investor owned electric utility shall transfer to a distinct
corporate entity all generation assets and generation-related business
activities, including electric energy sales activities, and generation-
related contracts, except as provided in subsection 3. The commission
shall determine the extent of separation between affiliates that is
required under this subsection.
2. Interests in generation restricted. Except as otherwise
provided in this section, on or after January 1, 2000, no investor owned
transmission and distribution utility may:
A. Acquire or hold any financial or ownership interest in
generation assets or generation-related business activities or
contracts for generation; or
B. Produce, purchase, sell, market, aggregate customers, broker, or
engage in any similar activity relating to generation capacity or
energy.
Page 6 Appendix 2
3. Sale of capacity and energy required. Investor owned
utilities may not be required to transfer to a distinct corporate entity
contracts with a qualifying facility. Beginning January 1, 2000, each
large investor owned transmission and distribution utility shall sell all
rights to capacity and energy from its contracts with qualifying
facilities. Beginning January 1, 2006, each large investor owned
transmission and distribution utility shall sell all the rights to
capacity and energy from any contracts with the Maine Yankee Atomic Power
Company.
4. Divestiture required; exception. On or before January 1, 2006,
each large investor owned transmission and distribution utility shall
divest all generation assets and generation-related business activities,
except contracts with qualifying facilities and the Maine Yankee Atomic
Power Company. After divestiture, no large investor owned transmission
and distribution utility may have any affiliated interest in a competitive
generation provider.
5. Commission may require divestiture of Maine Yankee interests.
Notwithstanding any other provision of this chapter, the commission may,
if necessary to achieve the purposes of this chapter, require any investor
owned transmission and distribution utility to divest its interest in the
Maine Yankee Atomic Power Company on or after January 1, 2009.
6. Commission may require exempt utilities to divest. The
commission may require any small investor owned transmission and
distribution utility to divest, and thereafter have no affiliated interest
in a competitive generation provider, except contracts with qualifying
facilities and the Maine Yankee Atomic Power Company. In order to require
divestiture under this subsection, the commission must find that
divestiture is necessary to achieve the purposes of this chapter.
7. Generation assets permitted. On or after January 1, 2000,
notwithstanding any other provision in this chapter, the commission may
allow an investor owned transmission and distribution utility to own, have
a financial interest in, or otherwise control generation and generation-
related assets to the extent that the commission finds such ownership,
interest or control is necessary for the utility to perform its
obligations as a transmission and distribution utility in an efficient
manner. The transmission and distribution utility may not sell the energy
or capacity from generation that it owns, has a financial interest in, or
otherwise controls to any retail customer.
8. Retail marketing restricted; wholesale marketing prohibited;
exception. Except as provided in subsection 6, after January 1, 2006,
consumer owned transmission and distribution utilities and affiliated
interests of small investor owned transmission and distribution utilities:
Page 7 Appendix 2
A. May provide retail generation service only within their
respective service territories; and
B. May not provide wholesale generation service except that
incidental wholesale sales are permitted if necessary to reduce the
cost of providing retail service.
SS 6. Regulation of transmission and distribution utilities
Nothing in this chapter limits the commission's authority to
regulate electric transmission and distribution service and to ensure that
all consumers of electricity are afforded transmission and distribution
service at just and reasonable rates.
SS 7. Stranded cost recovery
Beginning with the implementation of retail access, the commission
shall provide electric utilities a reasonable opportunity to recover,
through the rates of the transmission and distribution utility,
legitimate, verifiable and unmitigatable costs made unrecoverable as a
result of retail access. Prior to the implementation of retail access,
the commission shall determine the amount of these costs for each electric
utility and may subsequently adjust these costs as necessary.
SS 8. Standard offer service
At the time retail access begins, the commission shall ensure that
standard offer service is available to all consumers of electricity,
except that the Commission may establish eligibility requirements that
exclude consumers of electricity with demands above a specified amount if
the Commission finds that these consumers do not need standard offer
service and their eligibility for the service would increase its costs.
The commission shall establish terms and conditions for standard offer
service. Standard offer service must be available until January 1, 2005
and may be continued after that date if the commission finds it necessary.
Nothing in this section precludes the commission from permitting or
requiring different terms and conditions for standard offer service in
different utility service territories and for different customer classes.
SS 9. Consumer protection
The commission shall ensure that all retail customers are protected
to the greatest extent possible from unfair trade practices, fraud, and
other unreasonable practices by competitive generation providers and
transmission and distribution utilities.
Page 8 Appendix 2
1. Authority. In implementing this section, the commission,
notwithstanding any other provision of this chapter:
A. Registration. Shall impose reasonable registration requirements
on competitive generation providers;
B. Consumer protection standards. Shall establish consumer
protection standards to protect retail consumers of electricity
from fraud or other unreasonable business practices. Violations of
the consumer protection standards shall be a civil violation for
which the Commission may impose penalties, not exceeding $5,000 for
each occurrence.
C. Dispute resolution. Shall resolve disputes between
competitive generation providers and retail consumers of
electricity with respect to Commission established customer
protection standards;
D. Disconnection restricted. May forbid transmission and
distribution utilities from disconnecting electric service to any
consumer of electricity based on nonpayment of charges owed or
alleged to be owed to any competitive generation provider. The
commission may permit disconnection of electric service to
consumers of electricity based on nonpayment of charges for
standard offer service;
E. Disclosure. May require the disclosure, to the extent
necessary to achieve the purposes of this chapter, of information
about the competitive generation provider's services, including,
but not limited to information about the characteristics of the
generation assets used by the competitive generation provider. The
Commission shall provide for reasonable confidentiality
protections, if necessary;
F. Maine Unfair Trade Practices Act. Has concurrent authority
with the Attorney General to act under the Maine Unfair Trade
Practices Act with respect to retail sales activities of
competitive generation providers; and
G. Additional actions. May impose any additional requirements
necessary to carry out the purposes of this chapter, except that
this section may not be construed to permit the commission to
regulate the rates of any competitive generation provider.
Page 9 Appendix 2
SS 10. Energy policy
The commission shall, in a manner consistent with the requirements
of an efficient and effective competitive market for electricity, promote
the development and use of renewable resources in producing electric power
and promote the use of conservation and load management.
1. Authority. In carrying out the requirements of this section,
the commission may, without limitation on other actions it considers
necessary:
A. Renewable resources. Require competitive generation providers
to produce, or obtain credits for, a specified portion of their
electric power sold to consumers of electricity in the state using
renewable resources; and
B. Conservation programs. Require transmission and distribution
utilities to implement energy conservation programs and include the
cost of any such programs in rates.
SS 11. Consumer education and information
The commission shall take all steps necessary to ensure that, prior
to the implementation of retail access, electricity consumers are aware,
to the greatest extent practicable, of the opportunities and risks of
electric restructuring.
1. Authority. In implementing this section, the commission may,
without limitation on other actions it considers necessary:
A. Unbundled bills. Require electric utilities to issue bills
which, to the extent practicable, state the current cost of
electric capacity and energy separately from other charges for
electric service; and
B. Publish information. Publish and disseminate, through
whatever means it considers appropriate, information that will
enhance customers' ability to exercise their choices in a
competitive electricity market effectively.
SS 12. Commission proceedings and report
1. Commission proceedings. The commission shall conduct any
proceedings necessary to implement this chapter. Nothing in this chapter
is intended to exempt the commission from the requirements of Title 5,
section 8071, to the extent the Commission adopts any major substantive
rules.
Page 10 Appendix 2
2. Annual restructuring report. On December 31st of each
calendar year, the commission shall submit to the Joint Standing Committee
on Utilities and Energy, a report describing the commission's activities
in carrying out the requirements of this chapter and further describing
activities relating to changes in the regulation of electric utilities in
other jurisdictions.
SS 13. Proposed changes
If the commission determines, after providing interested parties an
opportunity to be heard, that any provision in this chapter is not in the
public interest, the commission shall present a report to the joint
standing committee of the Legislature having jurisdiction over utility
matters stating the basis for the commission's conclusion and including
draft legislation designed to modify this chapter consistent with the
public interest.
Sec. 2. Recommendation for Low Income Program. On or before
January 1, 1998, the commission and the State Planning Office shall
provide to the Joint Standing Committee on Utilities and Energy, to the
Joint Standing Committee on Appropriations and Financial Affairs, to the
Joint Standing Committee on Taxation, and to any other committees of
relevant jurisdiction, draft legislation that would fund assistance to low
income consumers of electricity through the general fund or through a tax
on all energy sources in the state.
Sec. 3. Market power report. On or before December 1, 1998, the
commission shall submit a report to the Joint Standing Committee on
Utilities and Energy, on whether market power exists or is likely to arise
in the generation market in New England.
Sec. 4. Conforming amendments. The commission shall identify and
submit to the Legislature by December 31, 1998, for enactment any
amendments required to conform other statutes to the provisions of this
Act.
Exhibit 99(p)
UNITED STATES DISTRICT COURT
DISTRICT OF MAINE
PEOPLES HERITAGE BANK, et al, )
)
Plaintiffs )
)
)
vs. )
) Civil No. 95-0180-B
MAINE PUBLIC SERVICE COMPANY, )
)
Defendant )
J U D G M E N T
This matter having come before the Court, Honorable Eugene W. Beaulieu
presiding, and the issues having been duly tried, and pursuant to the
Findings of Fact and Conclusions of Law entered by the Court on December 2,
1996,
JUDGEMENT is hereby entered for Defendant and against the Plaintiffs.
Dated this 2nd day of December, 1996.
WILLIAM S. BROWNELL, CLERK
/s/ Harriett D. Jefferson
Harriett D. Jefferson,
Case Manager
UNITED STATES DISTRICT COURT
DISTRICT OF MAINE
PEOPLES HERITAGE BANK, and )
APEX, INC. )
)
Plaintiffs )
)
v. ) Civil No. 95-0180-B
)
MAINE PUBLIC SERVICE COMPANY, )
)
Defendant )
FINDINGS OF FACT AND CONCLUSIONS OF LAW /1
This is an action arising out of costs incurred by Plaintiffs in
remediating environmental contamination at property they allege was
contaminated by Defendant's electrical transformers. The matter came before
the Court for bench trial beginning on July 22, 1996. Following trial, the
parties were directed to submit proposed findings and conclusions for the
Court's review, and those materials have been submitted. Based upon a review
of the proposed findings and conclusions, as well as the evidence presented
at trial, the Court hereby enters the following Findings of Fact and
Conclusions of Law.
FINDINGS OF FACT
1. In September, 1992, the Asset Management Department of Peoples
Heritage Bank ["PEOPLES"] purchased the Mitchell Trucking property in Presque
Isle, Maine ["THE SITE"] at a foreclosure auction. Peoples' bid was assigned
to APEX, Inc. ["APEX"], a subsidiary of Peoples that holds, manages, and
sells foreclosed properties.
______________________
1/ Pursuant to Federal Rule of Civil Procedure 73(b), the parties have
consented to allow the United States Magistrate Judge to conduct any and all
proceedings in this matter.
2. Maine Public Service Company ["MPSC"] is an electric utility
located in Presque Isle, Maine, which provided electrical service to the Site
from 1956 to the present.
3. In October, 1992, County Environmental Engineering ["CEE"] began
a Department of Environmental Protection ["DEP"] site assessment at the Site.
During the assessment, CEE's excavator bucket hit cedar log cribbing material
about two feet below the surface. Inside the crib was two feet of watery
substance on top of two feet of a white pasty substance.
4. As directed by DEP, CEE placed the material in a dumpster located
east of the crib. Some of the material spilled as it was put into the
dumpster.
5. Samples taken of the soil around the area were tested, and found
to be contaminated with polychlorinated biphenyls ["PCBs"] at 330 parts per
million.
6. Higher concentrations (as high as 1800 parts per million) of PCBs
were found in other locations at the Site.
7. There are different types of PCBs, which are identified by a number
called an "Aroclor." The soil samples at the Site contained only Aroclor
1248.
8. Since 1956, MPSC has had at least six distribution transformers
located at the Site. One of those transformers has been shown to contain
Aroclor 1248 at concentrations perhaps as high as 7.5 parts per million.
9. Since 1956, the Site has been used by several manufacturing
concerns. Plaintiff's expert concedes, while believing the transformers
contaminated the Site, that there are other possibilities arising from these
earlier uses of the Site.
10. From 1956 to as late as 1964, Shalek Bag Company operated a
facility for the manufacture of burlap and paper bags on the Site. The
manufacturing processing involved the use of inks, dyes and solvents, at
least one of which is unidentified. The solvents were used to wash inks and
dyes from print rolls at a sink that drained into a cesspool located at the
approximate location of the crib.
11. Maine Potato Growers purchased the Site in 1965. From 1975 to
1980, the Site was leased to Converse Rubber Company. Converse used the
facility for the process of stitching canvas uppers to the rubber soles of
shoes.
12. The Site was sold to Mitchell Trucking Company in 1984, following
which four underground storage tanks were installed on the Site, one for
kerosene, one for diesel fuel, and two for No. 2 fuel oil. DEP records
indicate a spill from one of No. 2 fuel tanks in 1984.
13. Also in 1984, the utility poles were relocated and fill from an
unknown source was brought to the Site as part of a landscaping project.
Conclusions of Law
1. Defendant concedes that Plaintiffs are entitled to the security
interest exception to liability under the Comprehensive Environmental
Response, Compensation, and Liability Act ["CERCLA"], 42 U.S.C. SS-SS 9601-
9675. See Northeast Doran v. Key Bank of Maine, 15 F.3d 1, 2-3 (1st Cir.
1994). Accordingly, Plaintiff's claim in Count II for contribution under
section 113 of CERCLA, 42 U.S.C. SS 9613, is hereby DISMISSED. See United
Tech. v. Browning-Ferris Ind., 33 F.3d 96, 103 (1st Cir. 1994).
2. Defendant concedes that its transformers are "facilities" under
CERCLA, and that it is therefore a "covered person" within the meaning of
CERCLA, inasmuch as it is an owner operator of a facility on the Site. 42
U.S.C. SS 9607.
3. Defendant concedes Plaintiffs have incurred necessary costs of
response in remediation of the contamination found at the Site. 42 U.S.C.
SS-SS 9601(25), 9607(a)(4)(B).
4. The Court finds that Plaintiffs have failed to prove by a
preponderance of the evidence that there was a "release of a hazardous
substance from" the distribution transformers located on the Site and owned
by Defendant. 42 U.S.C. SS 9607(a); Dedham Water v. Cumberland Farms Dairy,
889 F.2d 1146, 1151 (1st Cir. 1989). Plaintiffs ask the Court to infer that
the transformers must have been the source of the contamination on the basis
of one expert's opinion that none of the other uses of the Site could have
released Aroclor 1248. However, there were unidentified materials (including
the fill used by Mitchell Trucking and the cleaning solvent used by Shalek
Bag Company) present on the Site. Further, there is an absence of evidence
(1) that any of the transformers contained Aroclor 1248 in anything near the
concentrations discovered on the Site, and (2) that any of the transformers
ever spilled onto the Site. Finally, there was credible expert testimony
that the other uses could have caused the contamination. On the record
before it, the court is simply unable to adopt the inference Plaintiffs
propose. Accordingly, Judgment is appropriately entered for Defendant on
Counts I and II of Plaintiffs' Complaint.
5. Plaintiffs dismissed their state law claims (Counts IV through
VIII) with prejudice on July 24, 1996.
Conclusion
Accordingly, Judgment shall enter for Defendant as against Plaintiffs
on all Counts of Plaintiffs' Complaint.
SO ORDERED.
/s/ E. W. Beaulieu
Eugene W. Beaulieu
U.S. Magistrate Judge
Dated at Bangor, Maine on December 2, 1996
Exhibit 99(q)
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders
of Maine Public Service Company
Presque Isle, Maine
We have audited the consolidated balance sheet and statement of capitalization
of Maine Public Service Company and its Subsidiary, Maine and New Brunswick
Electrical Power Company, Limited, as of December 31, 1995, and the related
consolidated statements of operations, common shareholders' equity, and cash
flows for each of the two years in the period ended December 31, 1995 listed in
the Index at Item 14. Our audits also included the financial statement schedule
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 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, such consolidated financial statements present fairly, in all
material respects, the financial position of Maine Public Service Company and
its subsidiary at December 31, 1995, and the results of their operations and
their cash flows for each of the two years in the period ended December 31,
1995 in conformity with generally accepted accounting principles. Also, in
our opinion, such financial statement schedule, for each of the two years in
the period 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.
DELOITTE & TOUCHE LLP
Boston, Massachusetts
February 14, 1996
[ARTICLE] UT
[PERIOD-TYPE] 12-MOS
[FISCAL-YEAR-END] DEC-31-1996
[PERIOD-END] DEC-31-1996
[BOOK-VALUE] PER-BOOK
[TOTAL-NET-UTILITY-PLANT] 50015
[OTHER-PROPERTY-AND-INVEST] 3659
[TOTAL-CURRENT-ASSETS] 11270
[TOTAL-DEFERRED-CHARGES] 51813
[OTHER-ASSETS] 0
[TOTAL-ASSETS] 116757
[COMMON] 7357
[CAPITAL-SURPLUS-PAID-IN] 38
[RETAINED-EARNINGS] 30697
[TOTAL-COMMON-STOCKHOLDERS-EQ] 38092
[PREFERRED-MANDATORY] 0
[PREFERRED] 0
[LONG-TERM-DEBT-NET] 39805
[SHORT-TERM-NOTES] 1400
[LONG-TERM-NOTES-PAYABLE] 0
[COMMERCIAL-PAPER-OBLIGATIONS] 0
[LONG-TERM-DEBT-CURRENT-PORT] 1315
[PREFERRED-STOCK-CURRENT] 0
[CAPITAL-LEASE-OBLIGATIONS] 0
[LEASES-CURRENT] 0
[OTHER-ITEMS-CAPITAL-AND-LIAB] 36145
[TOT-CAPITALIZATION-AND-LIAB] 116757
[GROSS-OPERATING-REVENUE] 57264
[INCOME-TAX-EXPENSE] 1955
[OTHER-OPERATING-EXPENSES] 50021
[TOTAL-OPERATING-EXPENSES] 51976
[OPERATING-INCOME-LOSS] 5288
[OTHER-INCOME-NET] 349
[INCOME-BEFORE-INTEREST-EXPEN] 5637
[TOTAL-INTEREST-EXPENSE] 3526
[NET-INCOME] 2111
[PREFERRED-STOCK-DIVIDENDS] 0
[EARNINGS-AVAILABLE-FOR-COMM] 2111
[COMMON-STOCK-DIVIDENDS] 2976
[TOTAL-INTEREST-ON-BONDS] 3096
[CASH-FLOW-OPERATIONS] 7385
[EPS-PRIMARY] 1.305
[EPS-DILUTED] 1.305