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, 1998. Commission File No. 1-3429
Maine Public Service Company
(Exact name of registrant as specified in its charter)
Maine 01-0113635
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
209 State Street, Presque Isle, Maine 04769
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 207-768-5811
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Common Stock, $7.00 par value American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Title of Class
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X . No .
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates at March
19, 1999: $ 23,450,125.
The number of shares outstanding of each of the issuer's classes of common
stock as of March 19, 1999.
Common Stock, $7.00 par value - 1,617,250 shares
DOCUMENTS INCORPORATED BY REFERENCE
1. The Company's 1998 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, 1998, which is the
end of the fiscal year covered by this report, is incorporated by reference
into Part III.
(Page 1 of 48 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 1998, sales to the Company amounted to
92,365 MWH out of the 117,374 MWH generated for sale at Tinker.
As discussed further in Items 3(a) and (b) of the "Legal
Proceedings" section of this Form 10-K, the Company is proceeding with
the sale of generating assets in accordance with Maine's electric
utility deregulation law.
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Form 10-K
PART I
Item 1. Business - Continued
The Company and the Subsidiary's net energy production, including
generated and purchased power, required to serve all customers, was
655,211 MWH for the twelve months ended December 31, 1998. The
following table sets forth the sources from which the Company and the
Subsidiary obtained their power requirements in 1998.
1998 Megawatt-hours Generated
Sources of Power or Purchased
Net Generation:
Hydro 123,288
Steam 35,764
Diesel (799)
Total 158,253
Purchases:
Fossil Fuel Generated 161,302
Biomass Generated 339,705
Total 501,007
Inadvertent Received (4,049)
Total System 655,211
As of June 4, 1984, the Company entered into a Power Purchase
Agreement (PPA) with Sherman Power Company, which assigned its interest
in the Agreement to Wheelabrator-Sherman Energy Company (W-S), formerly
Signal-Sherman Energy Company, (a cogenerator), for 17.6 MW of capacity
which began July, 1986. The original contract was scheduled to expire
in 2001. As explained in Item 3(f) of the "Legal Proceedings" section
of this Form 10-K, on October 15, 1997, the Company and W-S agreed to
amend the PPA. Under the terms of this amendment, W-S agreed to
reductions in the price of purchased power of approximately $10 million
over the PPA's current term. The Company and W-S have agreed to renew
the PPA for an additional six years at agreed-upon prices. The Company
made an up-front payment to W-S of $8.7 million on May 29, 1998, with
the financing provided by the Finance Authority of Maine (FAME). This
payment has been reflected as a regulatory asset and, based on an MPUC
order, will be included in stranded costs and will be recovered in the
rates of the transmission and distribution utility. The Company
believes the amended PPA will help relieve the financial pressure caused
by the recent closure of Maine Yankee as well as the need for
substantial increases in its retail rates, and is therefore in the best
interests of the Company, its customers and shareholders.
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Form 10-K
PART I
Item 1. Business - Continued
Financial Information about Foreign and Domestic Operations
Financial Information Relating
To Foreign and Domestic Operations
(In Thousands of U.S. Dollars)
1998 1997 1996
Revenues from
Unaffiliated Customers:
Company-United States 55,958 54,291 56,521
Subsidiary-Canada 669 781 743
Intercompany Revenues:
Company-United States 644 728 683
Subsidiary-Canada 1,748 1,672 2,424
Operating Income:
Company-United States 5,785 567 4,585
Subsidiary-Canada 380 344 703
Net Income (Loss)
Company-United States 1,886 (2,521) 1,366
Subsidiary-Canada 367 344 745
Identifiable Assets:
Company-United States 157,476 156,207 109,891
Subsidiary-Canada 6,820 7,274 6,823
The identifiable assets, by company, are those assets used in each
company's operations, excluding intercompany receivables and investments.
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Form 10-K
PART I
Item 1. Business - Continued
Source of Revenues
In 1998, consolidated operating revenues totaled $56,626,906.
The percentages of revenues derived from customer classes are as follows:
%
Residential 36.4
Small Commercial and Industrial 32.4
Large Commercial and Industrial 18.1
Sales to Wholesale Customers for Resale 3.3
Other Sales and Other Revenues 9.8
Total 100.0
Sales to wholesale customers for resale includes two wholesale
customers, Van Buren Light and Power District (Van Buren) and Eastern
Maine Electric Cooperative, Inc. (EMEC), that selected the Company's
six-year proposal in 1994 and subsequently amended, which could not be
terminated before December 31, 1998. Van Buren and EMEC represented
4.3% of consolidated MWH sales and 2.2% of consolidated operating
revenues for the year ended December 31, 1998. These contracts
contained rates lower than those typically allowed under FERC's
traditional ratemaking. Capitalizing on the availability of low cost
power in New England, the wholesale customers issued a request for
proposal in September, 1994 for their purchased power requirements
effective January 1, 1996. Houlton Water Company (Houlton), selected an
offer from another utility, and began taking service from that utility
starting January 1, 1996. In 1995, Houlton was the Company's largest
customer. On July 1, 1998, Houlton entered into a new contract,
effective February 3, 1999, to purchase its power at a reduced rate from
the Company. This contract is effective through December 31, 2000, and
may not be terminated before March 1, 2000.
During 1996 and 1997, the Company entered into long-term power
contracts with five of its largest customers. In exchange for discounts
from the Company's standard rates, these customers agreed to purchase
all of their electrical requirements from the Company through the year
2000. All five of these customers produced evidence of hardship to
continue operations in the area or were investigating self generation,
criteria that the Maine Public Utilities Commission (MPUC) reviewed
before approving these load-retention contracts.
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Form 10-K
PART I
Item 1. Business - Continued
On November 13, 1995, the Maine Public Utilities Commission
approved a Stipulation signed by Maine Public Service Company, the
Commission Staff and the Maine Office of the 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. The multi-
year rate plan was subsequently amended in January, 1998. For more
information on the rate plan, see Item 3(h) of the "Legal Proceedings"
section of this Form 10-K.
For additional discussion on revenues, see the 1998 Annual Report
to Stockholders, pages 4 and 5, "Analysis of Financial Condition and
Review of Operations-Operating Revenues and Energy Sales" and pages 9
to 12, "Regulatory Proceedings", which information is incorporated
herein by reference.
Regulation and Rates
The Company is subject to the regulatory authority of the Maine
Public Utilities Commission (MPUC) as to retail rates, accounting,
service standards, territory served, the issuance of securities and
various other matters. With respect to wholesale rates and certain
other matters, the Company is or may be subject to the jurisdiction of
the Federal Energy Regulatory Commission (FERC). The Company maintains
its accounts in accordance with the accounting requirements of the FERC
which generally conform with the accounting requirements of the MPUC.
At this time, the Company is not subject to the Public Utilities
Regulatory Policies Act of 1978 ("PURPA") because it has not exceeded
the threshold of 2,000,000,000 kilowatt-hours excluding wholesale sales.
However, the Maine Legislature has by statute instructed the MPUC that
it may consider PURPA standards in rate proceedings before that
Commission.
The generating facilities of the Company and Subsidiary meet the
applicable current environmental regulations of State and Federal
governments of the United States and Provincial and Dominion governments
of Canada, except for the three diesel stations (12 MW) and the oil-
fired generating plant located in Caribou, Maine (23 MW). As discussed
in Item 2. "Properties" below, the oil-fired Steam Units 1 and 2 at the
Caribou facility have been placed on an inactive status. The Maine
Department of Environmental Protection (DEP), in response to the
Company's application for air emission licenses, has indicated that the
application did not demonstrate that Ambient Air Quality Standards and
Increments will not be violated. With the cooperation of the DEP Staff,
the Company is studying what steps, if any, are required for licensing,
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Form 10-K
PART I
Item 1. Business - Continued
and cannot determine at this time what, if any, additional capital
expenditures may be required. As discussed in Items 3(a) and (b) of the
"Legal Proceedings" section of this Form 10-K, the Company is proceeding
with the sale of generating assets in accordance with Maine's new
electric deregulation law.
See the 1998 Annual Report to Stockholders, pages 9 to 12,
"Analysis of Financial Condition and Review of Operations - Regulatory
Proceedings", which information is incorporated herein by reference, for
additional information on regulatory matters.
Franchises and Competition
Except for consumers served at retail by the Company's wholesale
customers, the Company has practically an exclusive franchise to provide
electric energy in the Company's service area. For additional
information on changes to the future structure of the electric utility
industry in Maine, see Item 3(a) of the "Legal Proceedings" section of
this Form 10-K.
Employees
The information with respect to employees is presented in the 1998
Annual Report to Stockholders, page 9, "Employees", which information is
incorporated herein by reference.
Subsidiaries and Affiliated Companies
The Company owns 100% of the Common Stock of Maine and New
Brunswick Electrical Power Company, Limited (the Subsidiary). The
Subsidiary owns and operates the Tinker Station located in the Province
of New Brunswick, Canada. The Tinker Station has five hydro units with
total capacity of 33,500 kilowatts and a small diesel unit of 1,000
kilowatts. The Subsidiary serves the community of Perth-Andover in New
Brunswick, with the remaining energy exported to the Parent Company in
Maine under license of the National Energy Board of Canada. On June 16,
1988, the export license was renewed to 2008.
On August 24, 1998, the MPUC approved the formation of the
Company's unregulated subsidiary, Energy Atlantic, LLC (EA). EA began
formal operations on January 1, 1999, performing various non-core
activities, such as retail and wholesale marketing of electric power and
the sales of energy-related products and services.
The Company owns 5% of the Common Stock of Maine Yankee, which
operated an 860 MW nuclear power plant (the "Plant") in Wiscasset,
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Form 10-K
PART I
Item 1. Business - Continued
Maine. On August 6, 1997, the Board of Directors of Maine Yankee voted
to permanently cease power operations and to begin decommissioning the
Plant. The Plant experienced a number of operational and regulatory
problems and did not operate after December 6, 1996. The decision to
close the Plant permanently was based on an economic analysis of the
costs, risks and uncertainties associated with operating the Plant
compared to those associated with closing and decommissioning it. The
Plant's operating license from the Nuclear Regulatory Commission (NRC)
was due to expire on October 21, 2008.
The Maine Public Utilities Commission (MPUC) stayed an
investigation of the prudency of the shutdown decision and the operation
of Maine Yankee prior to the shutdown decision, pending the outcome of
Maine Yankee's rate case before the Federal Energy Regulatory Commission
(FERC). The MPUC and the Maine Office of the Public Advocate (OPA) are
actively participating in the FERC proceeding, as well as 28 municipal
and cooperative utilities in New England who received approximately 6.2%
of the output from Maine Yankee (the "Secondary Purchasers").
In support of its request for an increase in decommissioning
collections, Maine Yankee submitted with its initial FERC rate case
filing a 1997 decommissioning cost study performed by TLG Services, Inc.
("TLG"). During 1998, Maine Yankee engaged in an extensive competitive
bid process to engage a Decommissioning Operations Contractor ("DOC") to
perform certain major decontamination and dismantlement activities at
the Plant on a fixed-price, turnkey basis. As a result of that process,
a consortium headed by Stone & Webster Engineering Corporation ("Stone
& Webster") was selected to perform such activities under a fixed-price
contract. The contract provides for, among other undertakings,
construction of an independent spent fuel storage installation ("ISFSI")
and completion of major decommissioning activities and site restoration
by the end of 2004. The DOC process resulted in fixing certain costs
that had been estimated in the earlier decommissioning cost estimate
performed by TLG.
Since the filing of the FERC rate request, Maine Yankee and the
active intervenors, including among others the MPUC Staff, the OPA, the
Company and other owners, the Secondary Purchasers, and a Maine
environmental group (the "Settling Parties"), engaged in extensive
discovery and negotiations. Those parties participated in settlement
discussions that resulted in an Offer of Settlement filed by those
parties with the FERC on January 19, 1999. On February 8, 1999, the
FERC Trial Staff recommended that the presiding judge certify the
settlement to the FERC and that the FERC approve it. Upon approval by
the FERC, the settlement would constitute a full settlement of all
issues raised in the consolidated FERC proceeding, including
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Form 10-K
PART I
Item 1. Business - Continued
decommissioning-cost issues and issues pertaining to the prudence of the
management, operation, and decision to permanently cease operation of
the Plant. A separately negotiated settlement filed with the FERC on
February 5, 1999 would resolve the issues raised by the Secondary
Purchasers by limiting the amounts they will pay for decommissioning the
Plant and by settling other points of contention affecting individual
Secondary Purchasers.
The Offer of Settlement provides for Maine Yankee to collect $33.6
million in the aggregate annually, effective January 15, 1998 consisting
of: (1) $26.8 million for estimated decommissioning costs, and (2) $6.8
million for ISFSI-related costs. The original filing with FERC on
November 6, 1997, called for an aggregate annual collection rate of
$36.4 million for decommissioning and the ISFSI, based on the TLG
estimate. Under the settlement the amount collected annually could be
reduced to approximately $26 million if Maine Yankee is able to (1) use
for construction of the ISFSI funds held in trust under Maine law for
spent-fuel disposal, and (2) access approximately $6.8 million being
held by the State of Maine for eventual payment to the State of Texas
pursuant to a compact for low-level nuclear waste disposal, the future
of which is now in question after rejection of the selected disposal
site in west Texas by a Texas regulatory agency. Both would require
authorizing legislation in Maine, which Maine Yankee is committed to use
its best efforts to obtain.
The Offer of Settlement also provides for recovery of all
unamortized investment (including fuel) in the Plant, together with a
return on equity of 6.50 percent, effective January 15, 1998, on equity
balances up to certain maximum allowed equity amounts. The Settling
Parties also agreed in the proposed settlement not to contest the
effectiveness of the Amendatory Agreements submitted to FERC as part of
the original filing, subject to certain limitations including the right
to challenge any accelerated recovery of unamortized investment under
the terms of the Amendatory Agreements after a required informational
filing with the FERC by Maine Yankee.
As a separate part of the Offer of Settlement, the Company, Central
Maine Power Company, and Bangor Hydro-Electric Company (the other two
Maine owners of Maine Yankee), the MPUC Staff, and the OPA entered into
a further agreement resolving retail rate issues and other issues
specific to the Maine parties, including those that had been raised
concerning the prudence of the operation and shutdown of the Plant (the
"Maine Agreement"). Under the Maine Agreement, the Company would
continue to recover its Maine Yankee costs in accordance with its most
recent Rate Stabilization Plan ("RSP") order from the MPUC without any
adjustment reflecting the outcome of the FERC proceeding. To the extent
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Form 10-K
PART I
Item 1. Business - Continued
that the Company has collected from its retail customers a return on
equity in excess of the 6.50 percent contemplated by the Offer of
Settlement, no refunds would be required, but such excess amounts would
be credited to the customers to the extent required by the RSP.
The final major provision of the Maine Agreement requires the Maine
owners, for the period from March 1, 2000 through December 1, 2004, to
hold their Maine retail ratepayers harmless from the amounts by which
the replacement power costs for Maine Yankee exceed the replacement
power costs assumed in the report to the Maine Yankee Board of Directors
that served as a basis for the Plant shutdown decision, up to a maximum
cumulative amount of $41 million. The Company's share of that maximum
amount would be $4.1 million for the period. The Maine Agreement, which
was approved by the MPUC on December 22, 1998, also sets forth the
methodology for calculating such replacement power costs.
The Company believes the Offer of Settlement, including the Maine
Agreement, reasonably resolves the issues presented by the parties in
the Maine Yankee FERC proceeding. If the Offer of Settlement is
approved by the FERC, several significant uncertainties regarding the
recovery of Maine Yankee-related costs are eliminated. Although all of
the active parties to the proceeding have agreed to support or, with
respect to certain individual provisions, not oppose, the Offer of
Settlement, the Company cannot predict with certainty whether or in what
form the Offer of Settlement will be approved by the FERC.
With the closing of Maine Yankee, a provision of the Company's rate
plan allowing the deferral of 50% of the Maine Yankee replacement power
costs went into effect on June 6, 1997. For 1998, Maine Yankee
replacement power costs were offset by net savings from the restructured
Purchase Power Agreement with Wheelabrator-Sherman, in accordance with
the rate plan stipulation, resulting in a deferral of $1.1 million. As
of December 31, 1998, the Company has a deferred Maine Yankee
replacement power cost balance of approximately $3.5 million, subject to
recovery in accordance with the rate plan.
The February 1, 1998, rate increase, as described in Item 3(h) of
the "Legal Proceedings" section of this Form 10-K, included $562,000 of
the recoverable 1997 Maine Yankee replacement power costs with the
remaining costs to be included in the rate plan increase in 1999.
On September 1, 1997, Maine Yankee estimated the sum of the future
payments for the closing, decommissioning and recovery of the remaining
investment in Maine Yankee to be approximately $930 million, of which
the Company's 5% share would be approximately $46.5 million. In
December, 1998, Maine Yankee updated its estimate of decommissioning
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Form 10-K
PART I
Item 1. Business - Continued
costs based on the Settlement, as discussed above. Legislation enacted
in Maine in 1997 calls for restructuring the electric utility industry
and provides for recovery of decommissioning costs, to the extent
allowed by federal regulation, through the rates charged by the
transmission and distribution companies. Based on the Maine legislation
and regulatory precedent established by the FERC in its opinion relating
to the decommissioning of the Yankee Atomic nuclear plant, the Company
believes that it is entitled to recover substantially all of its share
of such costs from its customers and, as of December 31, 1998, is
carrying on its consolidated balance sheet a regulatory asset and a
corresponding liability in the amount of $36.0 million, which is the
September, 1997 cost estimate of $46.5 million discussed above reduced
by the Company's post-September 1, 1997 cost-of-service payments to
Maine Yankee and reflects the cost adjustments agreed to in the
Settlement.
The Company also owns 7.49% of the Common Stock of Maine Electric
Power Company, Inc. (MEPCO). MEPCO owns and operates a 345-KV
(kilovolt) transmission line about 180 miles long which connects the New
Brunswick Power (NB Power) system with the New England Power Pool. The
MEPCO transmission line is also the path by which Wyman No. 4 energy is
delivered northerly into the NB Power system and then wheeled to the
Parent Company through its interconnection with NBEPC at the
international border.
Year 2000 Issues
The Year 2000 issue is the result of computer programs being
written using two digits rather than four to define the applicable year.
Computer programs that have date-sensitive software using two digits
would recognize a date using "00" as the year 1900 rather than the year
2000, resulting in system failure or miscalculations. The Company has
been conducting an on-going assessment of its computer systems,
including embedded chip technology, to determine the potential technical
and economic impact which the Year 2000 issues might have on the
Company, its systems and its business operations. As part of this
process, the Company has reviewed the computer application systems
responsible for its billing, customer information system and accounting
transactions and has identified modifications necessary for those
systems. These modifications are principally being made to comply with
the electric industry restructuring requirements but have incorporated
changes that achieve Year 2000 compliance. The Company has also
reviewed its other mission critical systems in order to identify Year
2000 remediation or renovation measures needed for those systems and
intends to complete necessary modifications, renovations and testing of
all mission critical systems by July 1, 1999. The compliance plans and
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Form 10-K
PART I
Item 1. Business - Continued
implementation and testing milestones are based on the Company's best
estimates, which were derived from numerous assumptions of future
events, including the continued availability of certain resources, third
party modification plans and other known factors. In addition to the
review of internal systems, the Company is requesting assurances of Year
2000 compliance from third parties upon whom the Company relies. The
responses are being reviewed and concerns of non-compliance are being
pursued. The Company is attempting to obtain responses and prepare
contingency plans, where necessary, no later than July 1, 1999.
To date, the Company's review and testing has incurred
approximately $17,000 of internal labor, and has not revealed material
system modifications necessary to obtain Year 2000 compliance for
mission critical systems, other than the changes necessary for electric
industry restructuring discussed above. However, $50,000 has been
budgeted in 1999 for external expenditures for unforeseen modifications
to achieve Year 2000 compliance for mission critical technology.
The assessment phase of the Year 2000 compliance project is
essentially complete and the Company is identifying risks and most
reasonable likely worse case scenarios specific to the Year 2000 non-
compliance by the Company and third-party sources. For example, for
every day of a Company-wide shutdown, the Company would lose
approximately $187,000 in revenues. The Company will develop
appropriate plans for these risks no later than July 1, 1999, as
mentioned above. Although all reasonable and available efforts will be
made, the Company cannot predict the ultimate achievement of Year 2000
compliance due to its reliance on systems and third-parties outside the
Company's control.
Executive Officers
The executive officers of the registrant are as follows:
Office
Continuously
Name Age Held Since
Paul R. Cariani President and Chief 58 6/1/94
Executive Officer
Frederick C. Bustard Vice President, 61 6/1/96
Power Supply & Environment
Larry E. LaPlante Vice President, 47 6/1/96
Finance, Administration and Treasurer
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Form 10-K
PART I
Item 1. Business - Continued
Stephen A. Johnson Vice President, 51 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.
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 Office of the Public
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Form 10-K
PART I
Item 1. Business - Continued
Advocate 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 11, 1999.
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. As discussed in Items 3(a) and (b)
of the "Legal Proceedings" section of this Form 10-K, the Company is
proceeding with the sale of generating assets in accordance with the
State's new electric deregulation law.
The Board of Directors authorized placing on inactive status Steam
Units 1 and 2 of the Company's Caribou Generating Facility in Caribou,
Maine effective January 1, 1996. These two units, which represent 23 MW
of capacity, were expected to remain inactive for five years or longer
and were surplus to the Company's needs due to the closure of Loring Air
Force Base and the loss in 1996 of the Company's largest customer, the
Houlton Water Company. During the Units' inactive period, the plant
equipment will be protected and maintained by the installation of a
dehumidification system that will permit the Plant to return to service
in approximately six months.
Steam Unit No. 1 went into operation in the early 1950s and Unit
No. 2, in the mid 1950s. The Company still has a diesel generation
station of approximately 7 MW and a hydro facility of approximately 1 MW
and will continue to employ 7 employees at the Caribou facility.
As of December 31, 1998, the Company and Subsidiary had
approximately 442 pole miles of transmission lines and the Company owned
approximately 1,666 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.
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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.
Item 3. Legal Proceedings
(a) Restructuring of Maine's Electric Utility Industry.
In the Company's Form 10-K's for December 31, 1996 and
December 31, 1997, the Company described electric utility
restructuring efforts in Maine, including the Maine Public
Utilities Commission's (MPUC) recommendation to the
legislature. After months of hearings and deliberations, the
Maine legislature passed L.D. 1804, "An Act to Restructure the
State's Electric Industry", which the Governor signed into law
on May 29, 1997.
The principal provisions of the new law are as follows:
1) Beginning on March 1, 2000, all consumers of electricity
have the right to purchase generation services directly from
competitive electricity suppliers who will not be subject to
rate regulation.
2) By March 1, 2000, the Company, Central Maine Power
Company (CMP) and Bangor Hydro-Electric Company (BHE) must
divest of all generation related assets and business functions
except for:
(a) contracts with qualifying facilities, such as the
Company's power contract with Wheelabrator-Sherman (W-S),
and conservation providers;
(b) nuclear assets, namely, the Company's investment in
the Maine Yankee Atomic Power Company, however, the MPUC
may require divestiture on or after January 1, 2009;
(c) facilities located outside the United States, i.e.,
the Company's hydro facility in New Brunswick, Canada;
and
(d) assets that the MPUC determines necessary for the
operation of the transmission and distribution services.
The MPUC can grant an extension of the divestiture deadline if
the extension will improve the selling price. For assets not
divested, the utilities are required to sell the rights to the
energy and capacity from these assets. See item (b) below
regarding the divestiture of the Company's generating assets.
3) Billing and metering services will be subject to
competition beginning March 1, 2002, but permits the MPUC to
establish an earlier date, no sooner than March 1, 2000.
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4) The Company, through an unregulated affiliate, may market
and sell electricity both within and outside its current
service territory, without limitation. Both CMP and BHE are
limited to 33% of the load within their respective service
territories, but may sell an unlimited amount outside their
service territories. Consumer-owned utilities are allowed to
market and sell within their service territories, but the MPUC
can limit or prohibit competition in their service territory,
if the tax-exempt status of the consumer-owned utility is
threatened.
5) The Company will continue to provide transmission and
distribution services which will be subject to continued
regulation by the MPUC.
6) Maine electric utilities will be permitted a reasonable
opportunity to recover legitimate, verifiable and unmitigable
costs that are otherwise unrecoverable as a result of retail
competition in the electric utility industry. The MPUC shall
determine these stranded costs by considering:
a) the utility's regulatory assets related to
generation, i.e., the Company's unrecovered Seabrook
investment;
b) the difference between net plant investment in
generation assets compared to the market value for those
assets; and
c) the difference between future contract payments and
the market value of the purchased power contracts, i.e.,
the W-S contract.
By the end of 1999, the MPUC will have estimated the stranded
costs for the Company and the manner for the collection of
these costs by the transmission and distribution company.
Customers reducing or eliminating their consumption of
electricity by switching to self-generation, conversion to
alternative fuels or utilizing demand-side management measures
cannot be assessed exit or entry fees. The Company estimates
its stranded costs to be approximately $99.3 million, based on
market power estimates beyond 2000 and regulatory treatment of
the Company's remaining Seabrook investment, but does not
include any benefits from the Company's sale of generating
assets. The MPUC shall include in the rates to be charged by
the transmission and distribution utility decommissioning
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Item 3. Legal Proceedings - Continued
expenses for Maine Yankee. In 2003 and every three years
thereafter until the stranded costs are recovered, the MPUC
shall review and revaluate the stranded cost recovery.
7) All competitive providers of retail electricity must be
licensed and registered with the MPUC and meet certain
financial standards, comply with customer notification
requirements, adhere to customer solicitation requirements and
are subject to unfair trade practice laws. Competitive
electricity providers must have at least 30% renewable
resources in their energy portfolios, including hydro-electric
generation.
8) A standard-offer service will be available, ensuring
access for all customers to reasonably priced electric power.
Unregulated affiliates of CMP and BHE providing retail
electric power are prohibited from providing more than 20% of
the load within their respective service territories under the
standard offer service, while any unregulated affiliate of the
Company does not have a similar restriction.
9) Unregulated affiliates of CMP and BHE marketing and
selling retail electric power must adhere to specific codes of
conduct, including, among others:
a) employees of the unregulated affiliate providing
retail electric power must be physically separated from
the regulated distribution affiliate and cannot be
shared;
b) the regulated distribution affiliate must provide
equal access to customer information;
c) the regulated distribution company cannot
participate in joint advertising or marketing programs
with the unregulated affiliate providing retail electric
power;
d) the distribution company and its unregulated
affiliated provider of retail electric power must keep
separate books of accounts and records; and
(e) the distribution company cannot condition or tie the
provision of any regulated service to the provision of
any service provided by the unregulated affiliated
provider of electricity.
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Item 3. Legal Proceedings - Continued
The MPUC shall determine the extent of separation
required in the case of the Company to avoid cross-
subsidization and shall consider all similar relevant
issues as well as the Company's small size.
10) Employees, other than officers, displaced as a result of
retail competition will be entitled to certain severance
benefits and retraining programs. These costs will be
recovered through charges collected by the regulated
distribution company.
11) Other provisions of the new law include provisions for:
a) consumer education;
b) continuation of low-income programs and demand side
management activities;
c) consumer protection provisions;
d) new enforcement authority for the MPUC to protect
consumers.
(b) Maine Public Service Company, Request for Approval of Sale of
Generating Assets, Docket No. 98-584
Reference is made to the Company's Form 8-K for July 7, 1998
and Form 10-Q for the quarter ended June 30, 1998, in which
the Company reported that it had agreed to sell all of its
generating assets to WPS Power Development, Inc. (WPS-PDI) for
$37.4 million.
On August 7, 1998, the Company filed with the MPUC for
approval of this sale. The proceeding was given the Docket
No. 98-584. The Public Advocate and the Houlton Water Company
(HWC) have intervened in this proceeding. As reported in the
Company's Form 10-Q for the quarter ended September 30, 1998,
the MPUC, in its order approving the Company's divestiture
plan in MPUC Docket No. 97-670, noted a number of concerns
that it would address in Docket No. 98-584. Principal among
these concerns is whether the Company's lack of any connection
to New England electrical markets, except through the Province
of New Brunswick, Canada (NB) and the transmission system
owned by the Maine Electric Power Company (the MEPCO line)
presented unique issues concerning development of an adequate
competitive retail market for electricity in northern Maine
and directed the Company to address these concerns when it
filed for approval in Docket No. 98-584.
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PART I
Item 3. Legal Proceedings - Continued
On January 29, 1999, the Company filed a Partial Stipulation
in this Docket. Under the terms of this Stipulation, the
parties agreed that access to northern Maine's electrical
markets exclusively through the transmission of the New
Brunswick Power Corporation (NB Power) and the MEPCO line "is
no longer a substantial barrier to the development of an
adequate retail market for electricity in northern Maine" and
that any market power issues in northern Maine should not
prevent the MPUC from approving the sale of the Company's
generation assets to WPS-PDI.
The basis for this Stipulation is a Products and Service
Agreement between NB Power, on the one hand, and the Company,
HWC, Eastern Maine Electric Cooperative, Inc. and the Van
Buren Light and Power District (collectively, "the northern
Maine utilities"), on the other. This Agreement is based in
large part upon the recommendations of the Final Report of the
Maine Attorney General described in (c) below. Under this
Agreement, NB Power agrees to supply: (i) tie-line
interruption service, on a firm or non-firm basis, to any
northern Maine utility requiring it; (ii) ancillary services
to any northern Maine utility; (iii) transmission services
through NB to any northern Maine utility at a fixed rate that
can be increased only by authorization of the proper NB
regulatory authority; and (iv) bona fide offers of energy and
capacity and other electric products and service to any
customer of any northern Maine utility. It is understood that
northern Maine utilities will transfer these services at cost
to competitive electricity providers.
On December 10, 1998, the MPUC issued a bench analysis
concerning certain aspects of the manner in which the Company
structured the proposed sale with WPS-PDI. Principal among
these concerns were whether the Company should withdraw from
the proposed sale of its interest in Wyman Unit No. 4 and
attempt to sell this asset independently in the New England
markets and whether the Company should retain title to
approximately 12 MW of diesel capacity. The Company addressed
these concerns in rebuttal testimony filed on January 19, 1999
and at a hearing on February 2, 1999. Although the MPUC must
ultimately pass on these issues, the Company does not believe
them to represent any obstacle to the proposed sale to WPS-
PDI.
The Company cannot, however, predict the MPUC's ultimate
decision regarding the market power issues addressed in the
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Item 3. Legal Proceedings - Continued
Partial Stipulation described above. A decision in this
Docket is expected by late March, 1999.
(c) Final Report by the Department of the Maine Attorney General
and the MPUC Regarding Market Power Issues Raised by the
Prospect of Retail Competition in Maine's Electric Industry,
Docket No. 97-877.
The Legislation described in item (a) above requires the Maine
Department of the Attorney General and the MPUC to jointly
conduct a study of the various market power issues presented
by the introduction of retail competition into Maine's
electric industry. This Report was issued on December 1,
1998.
With respect to market power in northern Maine, the Report
noted the potential for an unacceptably high level of market
power in northern Maine, arising from circumstances it
described as follows:
(i) "The northern Maine wholesale market is highly
concentrated, and subject to a corresponding degree of
market power. The market is dominated by NB Power, which
controls transmission access to northern Maine. NB Power
transmission is unsupervised by any regulatory authority,
and NB Power has set discriminatory rates, with the
result that it has preferential access to the market.
This transmission regime effectively excludes Hydro-
Quebec from the market as well as participants from New
England and Nova Scotia."
(ii) "In addition, there exists a transmission constraint
[over the MEPCO line] which prevents firm power from
flowing to northern Maine from New England. Moreover,
the problem of market power is probably aggravated by the
lack of access to a well-designed spot market."
Faced with these conclusions, the Report opined that "[t]he
question of whether retail choice in northern Maine should be
postponed must be confronted." The Report concluded, however,
that postponement should be a last resort and that other "less
drastic remedies" should be attempted first. The Report
specified certain of these remedies:
(i) regarding NB Power's dominance of the northern Maine
market, the Report proposed that NB Power contract with
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Item 3. Legal Proceedings - Continued
northern Maine T&D companies to provide transmission
service at a fixed, non-discriminatory rate;
(ii) regarding the lack of firm energy over the MEPCO line,
the Report proposed that NB Power should contract with
the northern Maine utilities to provide ancillary and so-
called tie-line interruption service, which would
effectively remove the south-to-north constraint on the
MEPCO line; and
(iii) finally, the Report concluded that if NB Power is
obligated to provide tie-line interruption service,
ancillary services and reasonably-priced transmission to
the northern Maine utilities, "the beneficial influence
of New England spot market pricing will be felt in
northern Maine."
As reported in item (b) above, the Products and Service
Agreement between NB Power and the northern Maine utilities
incorporates all of these proposals.
In a related matter, and again as required by the Legislature
described in item (a), the MPUC, on January 26, 1998, opened
an investigation into the feasibility of a direct physical
interconnection between the Company's service territory and
the New England power grid (Docket No. 97-586). On November
24, 1998, the Commission issued its final report, which was
prepared by an independent consultant. Like the Attorney
General's Report described above, this Study concluded that,
without changes such as those suggested in the Report, the
northern Maine market for electricity is likely to be subject
to market power problems.
(d) Maine Public Utilities Commission, Inquiry Into Bulk Power
System Administration and Settlement System in Northern Maine,
MPUC Docket No. 98-929.
On December 1, 1998, the MPUC issued its Notice of Inquiry
into the structure and operation of a bulk power system
administrator and retail settlement system for northern Maine.
This Inquiry was assigned MPUC Docket No. 98-529. The MPUC
based the need for this proceeding on the fact that northern
Maine is not electrically connected to the New England grid
and therefore systems in place in the rest of New England that
are necessary to support a marketable competitive environment
do not yet exist in northern Maine.
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Form 10-K
PART I
Item 3. Legal Proceedings - Continued
The MPUC Notice acknowledges that the four northern Maine
utilities - the Company, the Houlton Water Company, the
Eastern Maine Electric Cooperative, Inc. and the Van Buren
Light and Power District - have formed a working group for the
express purpose of developing these systems. The northern
Maine utilities are to develop and file a proposal for these
systems by April 30, 1999. The proposal will be developed
with the participation of various market participants,
including marketers, generators, customers and NB Power. The
Company is satisfied with the working groups' progress to
date, but cannot predict the success of any final outcome.
(e) 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.
On December 22, 1998, the FERC issued its order in this
proceeding. Although many of the major issues were not
decided in the Company's favor, the Company does not expect
the order to have any adverse impact on the Company's
financial condition. Based on the FERC order, the Company
expects to refund $1.2 million to the customers and has
reflected these refunds as liabilities.
(f) Restructured Purchase Power Agreement with Wheelabrator-
Sherman
The Company has a Power Purchase Agreement (PPA) with the
Wheelabrator-Sherman Energy Company (W-S) under which the
Company is obligated to purchase the entire output (up to
126,582 MWH) of a 17.6 MW biomass plant owned by W-S. The
original term of the PPA was scheduled to expire on December
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Item 3. Legal Proceedings - Continued
31, 2000 and was renewable by either party for an additional
fifteen years at prices to be determined by mutual agreement
or, absent mutual agreement, by the MPUC.
On October 15, 1997, the Company and W-S agreed to amend the
PPA. Under the terms of this amendment, W-S agreed to
reductions in the price of purchased power of approximately
$10 million over the PPA's current term in exchange for up-
front payments of $8.7 million. The Company and W-S also
agreed to renew the PPA for an additional six years at agreed-
upon prices. The Company believes the amended PPA will help
relieve the financial pressure caused by the recent closure of
Maine Yankee as well as the need for substantial increases in
its retail rates, and is therefore in the best interests of
the Company, its customers and shareholders.
In order to finance the up-front payment to W-S, the Company
concluded that it must obtain funds from the Finance Authority
of Maine (FAME); absent FAME financing the Company did not
believe it could obtain the funds on terms sufficiently
economic to justify the arrangement with W-S. The amended PPA
had to be approved by the MPUC before FAME financing could be
obtained. The Company's request for this approval was given
in MPUC Docket No. 97-727. The Company also asked the MPUC
for a determination that any so-called stranded costs created
by the amended PPA will be recoverable from customers to the
extent permitted by Maine law.
On December 22, 1997, the MPUC approved the amended PPA and
determined that the up-front payment required by the PPA will
be treated as stranded cost. On February 19, 1998, the FAME
Board of Directors voted to provide the Company with the
financing necessary to support the amended PPA. The Company
completed its financing with FAME on May 29, 1998 and the
amended PPA became effective June 1, 1998 with the up-front
payment of $8.7 million.
(g) Maine Public Utilities Commission Investigation of the
Operation and Shutdown of Maine Yankee Atomic Power Company
Generating Facility in Wiscasset, Maine, MPUC Docket No. 97-781
On October 24, 1997, the MPUC issued a Notice of Investigation
regarding the August, 1997 shutdown of the Maine Yankee Power
Plant (see Item 1. "Subsidiaries and Affiliated Companies",
above). The MPUC stated that the "permanent shutdown of the
plant presents significant ratemaking issues" such as
replacement power costs and stranded cost issues, for all
three of Maine Yankee's Maine owners. The announced scope of
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Form 10-K
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Item 3. Legal Proceedings - Continued
the investigation is therefore intended to focus on "two
separate generic prudence questions .... presented in
determining the reasonableness of increased purchased power
costs and reasonableness of the recovery of the unamortized
Maine Yankee investment:
1. Was the decision to shut down the Maine Yankee Plant
prudent?
2. Was the plant prematurely shut down because the plant had
been operated or was operating imprudently?"
As an owner of Maine Yankee, the Company was made a party to
this investigation.
The Company believes the MPUC's jurisdiction over Maine Yankee
costs and prudence issues is preempted by the Federal Power
Act and FERC jurisdiction. If, however, the MPUC should
successfully assert jurisdiction over these issues and, if it
disallowed substantial amounts of the Maine Yankee-related
expenses in retail rates, the effect on the Company's
financial condition would be material and adverse. On
November 7, 1997, Central Maine Power and Maine Yankee
initiated legal challenges to the MPUC investigation in the
Maine Supreme Judicial Court alleging that such an
investigation falls exclusively within the jurisdiction of the
FERC, and that the MPUC's investigation is therefore barred on
constitutional grounds. The Company joined that appeal on
November 13, 1997.
On December 2, 1997, the MPUC issued an Order staying the
investigation. The MPUC noted that Maine Yankee had begun a
rate proceeding before the FERC on November 6, 1997, which
could address the prudence issues raised in the MPUC's own
investigation. The MPUC therefore stayed its investigation in
order "to avoid unnecessary duplicative efforts by all parties
involved". The MPUC reserved the right to reopen the
investigation particularly if FERC declines to address the
prudence issues of concern to the MPUC "if we feel it
necessary to investigate those matters after the FERC
proceeding ends."
As a result, the Maine Supreme Judicial Court, on December 15,
1997, upon motion by Maine Yankee and its Maine owners, stayed
all proceedings in the appeal until the first to occur of
either December 31, 1998 or the 30th day after the conclusion
of Maine Yankee's rate case before the FERC.
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Form 10-K
PART I
Item 3. Legal Proceedings - Continued
The MPUC and the Maine Office of the Public Advocate (OPA) are
actively participating in the FERC proceeding, as well as 28
municipal and cooperative utilities in New England who
received approximately 6.2% of the output from Maine Yankee
(the "Secondary Purchasers").
In support of its request for an increase in decommissioning
collections, Maine Yankee submitted with its initial FERC rate
case filing a 1997 decommissioning cost study performed by TLG
Services, Inc. ("TLG"). During 1998, Maine Yankee engaged in
an extensive competitive bid process to engage a Decommissioning
Operations Contractor ("DOC") to perform certain major
decontamination and dismantlement activities at the Plant on a
fixed-price, turnkey basis. As a result of that process, a
consortium headed by Stone & Webster Engineering Corporation
("Stone & Webster") was selected to perform such activities under a
fixed-price contract. The contract provides for, among other
undertakings, construction of an independent spent fuel storage
installation ("ISFSI") and completion of major decommissioning
activities and site restoration by the end of 2004. The DOC process
resulted in fixing certain costs that had been estimated in the
earlier decommissioning cost estimate performed by TLG.
Since the filing of the FERC rate request, Maine Yankee and
the active intervenors, including among others the MPUC Staff,
the OPA, the Company and other owners, the Secondary
Purchasers, and a Maine environmental group (the "Settling
Parties"), engaged in extensive discovery and negotiations.
More recently, those parties participated in settlement
discussions that resulted in an Offer of Settlement filed by
those parties with the FERC on January 19, 1999, which, if
approved by the FERC, would result in full settlement of all
issues raised in the consolidated FERC proceeding, including
decommissioning-cost issues and issues pertaining to the
prudence of the management, operation, and decision to
permanently cease operation of the Plant. A separately
negotiated settlement filed with the FERC on February 5, 1999
would resolve the issues raised by the Secondary Purchasers by
limiting the amounts they will pay for decommissioning the
Plant and by settling other points of contention affecting
individual Secondary Purchasers.
The Offer of Settlement provides for Maine Yankee to collect
$33.6 million in the aggregate annually, effective January 15,
1998 consisting of: (1) $26.8 million for estimated
decommissioning costs, and (2) $6.8 million for ISFSI-related
costs. The original filing with FERC on November 6, 1997,
called for an aggregate annual collection rate of $36.4
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Form 10-K
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Item 3. Legal Proceedings - Continued
million for decommissioning and the ISFSI, based on the TLG
estimate. Under the settlement the amount collected annually could
be reduced to approximately $26 million if Maine Yankee is able to
(1) use for construction of the ISFSI funds held in trust under Maine
law for spent-fuel disposal, and (2) access approximately $6.8
million being held by the State of Maine for eventual payment to the
State of Texas pursuant to a compact for low-level nuclear waste
disposal, the future of which is now in question after rejection of
the selected disposal site in west Texas by a Texas regulatory
agency. Both would require authorizing legislation in Maine, which
Maine Yankee is committed to use its best efforts to obtain.
The Offer of Settlement also provides for recovery of all
unamortized investment (including fuel) in the Plant, together
with a return on equity of 6.50 percent, effective January 15,
1998, on equity balances up to certain maximum allowed equity
amounts. The Settling Parties also agreed in the proposed
settlement not to contest the effectiveness of the Amendatory
Agreements submitted to FERC as part of the original filing,
subject to certain limitations including the right to
challenge any accelerated recovery of unamortized investment
under the terms of the Amendatory Agreements after a required
informational filing with the FERC by Maine Yankee.
As a separate part of the Offer of Settlement, the Company,
Central Maine Power Company, and Bangor Hydro-Electric Company
(the other two Maine owners of Maine Yankee), the MPUC Staff,
and the OPA entered into a further agreement resolving retail
rate issues and other issues specific to the Maine parties,
including those that had been raised concerning the prudence
of the operation and shutdown of the Plant (the "Maine
Agreement"). Under the Maine Agreement, the Company would
continue to recover its Maine Yankee costs in accordance with
its most recent Rate Stabilization Plan ("RSP") order from the
MPUC without any adjustment reflecting the outcome of the FERC
proceeding. To the extent that the Company has collected from
its retail customers a return on equity in excess of the 6.50
percent contemplated by the Offer of Settlement, no refunds
would be required, but such excess amounts would be credited
to the customers to the extent required by the RSP.
The final major provision of the Maine Agreement requires the
Maine owners, for the period from March 1, 2000 through
December 1, 2004, to hold their Maine retail ratepayers
harmless from the amounts by which the replacement power costs
for Maine Yankee exceed the replacement power costs assumed in
the report to the Maine Yankee Board of Directors that served
as a basis for the Plant shutdown decision, up to a maximum
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Form 10-K
PART I
Item 3. Legal Proceedings - Continued
cumulative amount of $41 million. The Company's share of that
maximum amount would be $4.1 million for the period. The
Maine Agreement, which was approved by the MPUC on December
22, 1998, also sets forth the methodology for calculating such
replacement power costs.
The Company believes the Offer of Settlement, including the
Maine Agreement, reasonably resolves the issues presented by
the parties in the Maine Yankee FERC proceeding. If the Offer
of Settlement is approved by the FERC, several significant
uncertainties regarding the recovery of Maine Yankee-related
costs are eliminated. Although all of the active parties to
the proceeding have agreed to support or, with respect to
certain individual provisions, not oppose, the Offer of
Settlement, the Company cannot predict with certainty whether
or in what form the Offer of Settlement will be approved by
the FERC.
(h) Maine Public Utilities Commission Approves Rate Increase
Pursuant to Previously Approved Rate Plan, MPUC Docket
No. 97-830.
Reference is made to the Company's Form 10-K for December 31,
1996 where the Company's rate stabilization plan approved by
the Maine Public Utilities Commission (MPUC) (Docket No. 95-
052) in November, 1995 is described. In addition, in the
Company's Form 8-K filed November 19, 1997, the Company
announced its annual filing under the rate plan.
On November 13, 1997, the Company filed with the MPUC its
annual rate increase pursuant to the Company's rate plan. The
filing supported an annual increase in retail rates of 7.6%.
Additional capacity payments to restart Maine Yankee and
incremental replacement power costs adversely impacted the
Company's 1997 earnings and triggered the rate plan profit-
sharing mechanism.
In addition, the Company had amended its November, 1997 filing
requesting that the savings from the restructured
Wheelabrator-Sherman (W-S) Contract, as approved by the MPUC
on December 22, 1997 (see item (e) above) be used to offset
future Maine Yankee replacement power costs. The
restructuring of the W-S Contract required an up-front payment
of approximately $8.7 million, which the Company financed from
funds obtained from the Finance Authority of Maine (FAME),
under its rate stabilization program.
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PART I
Item 3. Legal Proceedings - Continued
On January 15, 1998, the OPA and the Company, with the support of
the MPUC Staff, reached an agreement on the rate increase for February
1, 1998. The principal elements of the stipulation are as follows:
- the rate increase effective February 1, 1998 was 3.9%,
consisting of the specified increase of 2.75% and
approximately $562,000 of the 1997 recoverable Maine
Yankee replacement power costs (1.15%);
- the minimum rate increase effective February 1, 1999 will
consist of a specified increase of 2% and the remaining
recoverable 1997 Maine Yankee replacement power costs of
$523,000;
- Maine Yankee replacement power costs for the period
October 1, 1997 through September 30, 1998 will be offset
by the 1998 savings under the restructured W-S contract,
with the recovery of any incremental Maine Yankee
replacement power costs subject to a final order by the
MPUC in its previously mentioned review of the prudency
of closing Maine Yankee;
- the Company wrote off in 1997 unamortized Maine Yankee
refueling outage costs of approximately $1,458,000;
- the Company waives its right to collect additional
revenues for the profit-sharing review period, i.e. the
twelve months ended September 30, 1997, since the
earnings deficiency was the result of the closing of
Maine Yankee and, based on the 3.9% increase granted by
the MPUC, the Company expects to earn a reasonable rate
of return in 1998 without these additional revenues.
This agreement was approved by the MPUC on January 26, 1998.
The Company was not able to attain its interest coverage tests
for the fourth quarter of 1997. On March 12, 1998, the
Company and the Banks executed a waiver of the interest
coverage tests for the fourth quarter of 1997, avoiding a
default. On March 31, 1998, the Company and the Banks
executed amendments to the revolving credit agreement and
letter of credit and reimbursement agreement, which further
adjusts the interest coverage tests for the first three
quarters of 1998. The Company met these new interest coverage
tests during 1998. For the fourth quarter of 1998, the
interest coverage tests, as prescribed in the underlying
documents without amendment, were also achieved by the
Company. The Company believes that its rate plan deals
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Form 10-K
PART I
Item 3. Legal Proceedings - Continued
effectively with the closing of Maine Yankee, with customers
and shareholders sharing the burden equally.
The Company is entitled to a final increase under the rate
plan on February 1, 1999. On November 13, 1998, the Company
filed with the MPUC for a 6.4% increase. The Company also
stated that it would forego part or all of this 1999 increase
if the sale of its generating assets was allowed to go
forward. As a result, the MPUC agreed to defer any scheduled
increase under the rate plan until at least April 1, 1999.
(i) Maine Public Service Company Investigation of Stranded Costs,
Transmission and Distribution Utility Revenue Requirements and
Rate Design, Docket No. 98-577
On October 14, 1998, and subsequently amended on February 9,
1999, the Company filed its determination of stranded costs,
transmission and distribution costs and rate design with the
MPUC. The Company's testimony supports its $99.3 million
estimate of stranded costs when deregulation occurs on March
1, 2000. The major components include the remaining
investment in Seabrook, the above market costs of the amended
power purchase agreement and recovery of fuel expense
deferrals related to Wheelabrator-Sherman, the obligation for
remaining operating expenses and recovery of the Company's
remaining investment in Maine Yankee, and the recovery of
several other regulatory assets. These stranded costs revenue
requirements will be reduced by an estimated $19.9 million
should the sale of the Company's generating assets be approved
by the MPUC, discussed further in item (b) above. The
Company's proposed annual revenue requirements supported in
the filings would be approximately $32.2 million: $19.8
million for transmission and distribution and $12.4 million
for stranded investment. Decisions by the MPUC regarding
stranded costs and the generating asset sale approval are not
expected until mid-1999. The Company cannot predict the
MPUC's ultimate decision in these matters.
-29-
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 12, 1998, the only matter voted upon was the
uncontested election of the following directors to serve
until the 2001 Annual Meeting of Stockholders, each of
whom received the votes shown:
Non-votes and
Nominee For Against Abstentions
Paul R. Cariani 1,406,045 21,708 189,497
Donald F. Collins 1,405,812 21,941 189,497
Richard G. Daigle 1,406,597 21,156 189,497
J. Gregory Freeman 1,406,595 21,158 189,497
-30-
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, 1998, there were
1,436 holders of record of the Company's Common Stock.
Dividend data and market price related to the Common Stock are
tabulated as follows for the two most recent calendar years:
Dividends
Market Price Dividends Declared
High Low Paid Per Share Per Share
1998
First Quarter $14-1/4 $11-3/4 $ .25 $ .25
Second Quarter $15-1/16 $13-15/16 .25 .25
Third Quarter $15-1/8 $14-1/16 .25 .25
Fourth Quarter $17-3/16 $13-5/16 .25 .25
Total Dividends $1.00 $1.00
1997
First Quarter $18-3/8 $14-1/8 $ .46 $ .25
Second Quarter $14-3/4 $11-3/8 .25 .25
Third Quarter $12-7/8 $10-3/16 .25 .25
Fourth Quarter $12-13/16 $11-3/8 .25 .25
Total Dividends $1.21 $1.00
Dividends declared within the quarter are paid on the first day of
the succeeding quarter.
See Note 6 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 (1994-1998) is
included on page 14 of the Company's 1998 Annual Report to
Stockholders, which summary is incorporated herein by
reference.
-31-
Form 10-K
PART II
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
The information required to be furnished in response to this
Item is submitted as pages 4 to 13, Exhibit 13, 1998 Annual
Report to Shareholders, which pages are hereby incorporated
herein by reference. Information regarding "Construction" is
also furnished in Note 10, "Commitments, Contingencies, and
Regulatory Matters", of the Notes to the Consolidated
Financial Statements, pages 27 to 31 of the 1998 Annual Report
to Shareholders, which pages are hereby incorporated herein by
reference.
-32-
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 1998 Annual Report to
Stockholders on pages 15 through 31, and are incorporated
herein by reference:
Report of Independent Accountants.
Statements of Consolidated Operations for the years
ended December 31, 1998, 1997 and 1996.
Statements of Consolidated Cash Flows for the years
ended December 31, 1998, 1997 and 1996.
Consolidated Balance Sheets as of December 31, 1998
and 1997.
Statements of Consolidated Common Shareholders'
Equity for the years ended December 31, 1998, 1997
and 1996.
Consolidated Statements of Capitalization as of
December 31, 1998 and 1997.
Notes to Consolidated Financial Statements.
Item 9. Changes In And Disagreements With Accountants On
Accounting and Financial Disclosure
None.
-33-
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 1999 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
1999 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 1999 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 1999 Annual Meeting of
Stockholders, which information is incorporated herein by
reference.
Item 13. Certain Relationships and Related Transactions
Not applicable.
-34-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K
(a) (1) Financial Statements
Report of Independent Accountants.
Incorporated by reference into Part II of this
report from pages 15 through 31 of the 1998 Annual
Report to Stockholders:
Statements of Consolidated Operations for years
ended December 31, 1998, 1997 and 1996.
Statements of Consolidated Cash Flows for the years
ended December 31, 1998, 1997 and 1996.
Consolidated Balance Sheets as of December 31, 1998
and 1997.
Statements of Consolidated Common Shareholders'
Equity for the years ended December 31, 1998, 1997
and 1996.
Consolidated Statements of Capitalization as of
December 31, 1998 and 1997.
Notes to Consolidated Financial Statements.
(2) Financial Statement Schedules
Included in Part IV of this report:
-35-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
Page
Report of Independent Accountants 47
Schedule II - Valuation of Qualifying Accounts 48
and Reserves
Schedules other than those listed above are omitted for the
reason that they are not required or are not applicable, or
the required information is shown in the financial statements
or notes thereto.
(3) Exhibits
Certain of the following exhibits are filed
herewith. Certain other of the following exhibits
have heretofore been filed with the Commission and
are incorporated herein by reference. (* indicates
filed herewith).
3(a) Restated Articles of Incorporation with all
amendments through May 8, 1990. (Exhibit 3(a)
to 1990 form 10-K)
3(b) By-laws of the Company, as amended through May
12, 1987. (Exhibit 3(b) to 1987 Form 10-K)
4(a) Indenture of Mortgage and Deed of Trust
defining the rights of the holders of the
Company's First Mortgage Bonds. (Exhibit 4(a)
to 1980 Form 10-K)
4(b) First Supplemental Indenture. (Exhibit 4(b)
to 1980 Form 10-K)
4(c) Second Supplemental Indenture. (Exhibit 4(c)
to 1980 Form 10-K)
4(d) Third Supplemental Indenture. (Exhibit 4(d)
to 1980 Form 10-K)
4(e) Fourth Supplemental Indenture. (Exhibit 4(e)
to 1980 Form 10-K)
4(f) Fifth Supplemental Indenture. (Exhibit A to
Form 8-K dated May 10, 1968)
4(g) Sixth Supplemental Indenture. (Exhibit A to
Form 8-K dated April 10, 1973)
-36-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
4(h) Seventh Supplemental Indenture. (Exhibit A to
Form 8-K dated November 7, 1975)
4(i) Eighth Supplemental Indenture. (Exhibit 4(i)
to 1980 Form 10-K)
4(j) Ninth Supplemental Indenture. (Exhibit B to
Form 10-Q for the second quarter of 1978)
4(k) Tenth Supplemental Indenture. (Exhibit 4(k)
to 1980 Form 10-K)
4(l) Eleventh Supplemental Indenture. (Exhibit
4(l) to 1982 Form 10-K)
4(m) Indenture defining the rights of the holders
of the Company's 9 7/8% debentures. (Exhibit
A to Form 8-K, dated June 10, 1970)
4(n) Indenture defining the rights of the holders
of the Company's 14% debentures. (Exhibit
4(n) to 1982 Form 10-K)
4(o) Twelfth Supplemental Indenture. (Exhibit 4(o)
to Form 10-Q for the quarter ended September
30, 1984)
4(p) Thirteenth Supplemental Indenture. (Exhibit
4(p) to Form 10-Q for the quarter ended
September 30, 1984)
4(q) Fourteenth Supplemental Indenture, Dated July
1, 1985. (Exhibit 4(q) to 1985 Form 10-K)
4(r) Fifteenth Supplemental Indenture, Dated March
1, 1986. (Exhibit 4(r) to 1985 Form 10-K)
4(s) Sixteenth Supplemental Indenture, Dated
September 1, 1991. (Exhibit 4(s) to the
Company's 1991 Form 10-K)
*4(t) Seventeenth Supplemental Indenture, Dated
April 1, 1997.
*4(u) Eighteenth Supplemental Indenture, Dated April
1, 1998.
-37-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
*4(v) Nineteenth Supplemental Indenture, Dated May 1, 1998.
9 Not applicable.
10(a)(1) Joint Ownership Agreement with Public Service
of New Hampshire in respect to construction of
two nuclear generating units designated as
Seabrook Units 1 and 2, together with related
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
-38-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
Company, Inc. (Exhibit 10(c)(4) to Form 10-Q
for quarter ended March 31, 1983)
10(c)(5) Second Supplement to Participation Agreement,
dated as of December 1, 1971, including as
Exhibit A the Unit Participation Agreement
dated November 15, 1971, as amended, between
Maine Electric Power Company, Inc. and the New
Brunswick Electric Power Commission. (Exhibit
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)
-39-
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
Bank and Trust Company, as Trustee, under an
Indenture of Mortgage and Deed of Trust, dated
as of October 1, 1945, as amended and
-40-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
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. (Exhibit 10(p) to 1995 Form 10-K)
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. (Exhibit 10(t) to 1996 Form 10-K)
10(u) Amendment No. 3, dated as of October 8, 1995,
to the Revolving Credit Agreement, dated as of
October 7, 1987, among the Registrant and The
Bank of New York, Shawmut Bank of Boston,
Fleet Bank of Maine, and The Bank of New York,
an agent for the participating Banks.
(Exhibit 10(u) to 1996 Form 10-K)
*10(v) Fourth Supplemental Indenture dated May 1, 1998.
-41-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
*10(w) Agreement between WPS Power Development, Inc.
and Maine Public Service Company, dated July
7, 1998.
*10(x) Agreement between Wheelabrator-Sherman Energy
Company and Maine Public Service Company,
dated October 15, 1997, with amendments dated
January 30, 1998 and April 28, 1998.
*10(y) Agreement between Loring Development Authority
of Maine and Maine Public Service Company,
dated July 9, 1998.
11 Not applicable.
12 Not applicable.
*13 1998 Annual Report to Shareholders.
16 March 8, 1996 Letter regarding change in
certifying accountant from Deloitte & Touche
LLP. (Exhibit 16 to the Company's 1996 Form
10-K)
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)
-42-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
99(c) Stipulation between Maine Public Service
Company, the Staff of the Commission and the
Maine Public Utilities Commission and the
Maine Public Advocate, dated July 14, 1986.
(Exhibit 28(c) to Form 10-Q for the quarter
ended June 30, 1986)
99(d) Amendment to July 14, 1986 Stipulation, dated
July 18, 1986. (Exhibit 28(d) to Form 10-Q
for the quarter ended June 30, 1986)
99(e) Order of the Maine Public Utilities Commission
dated July 21, 1986, Docket Nos 84-80, 84-113
and 86-3. (Exhibit 28(g) to 1986 Form 10-K)
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 of the Maine Public Utilities Commission
dated November 30, 1995 (with attached
Stipulation) in Docket No. 95-052. (Exhibit
28(p) to 1995 Form 10-K)
99(j) Order of the Federal Energy Regulatory
Commission dated May 31, 1995 in Docket No. ER
95-836-000. (Exhibit 28(r) to 1995 Form 10-K)
99(k) Order of Maine Public Utilities Commission
dated June 26, 1996 in Docket 95-052 (Rate
Design). (Exhibit 99(n) to 1996 Form 10-K)
99(l) Independent Auditors Report of Deloitte &
Touche L.L.P. dated February 14, 1996
regarding year ended December 31, 1995.
(Exhibit 99(l) to 1997 Form 10-K)
-43-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
99(m) Amendment No. 1, dated as of March 28, 1997,
to the Letter of Credit and Reimbursement
Agreement, dated as of June 1, 1996, among the
Registrant, The Bank of New York, Fleet Bank
of Maine, and The Bank of New York, as Agent
and Issuing Bank. (Exhibit 99(m) to 1997 Form
10-K)
99(n) Amendment No. 4, dated as of March 28, 1997,
to the Revolving Credit Agreement, dated as of
October 8, 1987, by and among the Registrant,
the signatory Banks thereto and The Bank of
New York, as Agent. (Exhibit 99(n) to 1997
Form 10-K)
99(o) Order of Maine Public Utilities Commission
dated January 30, 1998 in Docket No. 97-830
(Annual Increase under Rate Stabilization
Plan). (Exhibit 99(o) to 1997 Form 10-K)
99(p) Order by the Maine Public Utilities Commission
dated January 15, 1998 in Docket No. 97-727.
(Exhibit 99(q) to 1997 Form 10-K)
*99(q) Order of Maine Public Utilities Commission
dated February 20, 1998 in Docket 97-670
(Divestiture of Generation Assets).
*99(r) Order of Maine Public Utilities Commission
dated September 21, 1998 in Docket 98-138
(Formation of marketing affiliate).
*99(s) Order of Maine Public Utilities Commission
dated December 15, 1998 in Docket 98-865
(Annual Increase Under Rate Stabilization
Plan).
*99(t) Report of Synapse Energy Economics regarding
competition and market power in the northern
Maine market for the Maine Public Utilities
Commission for Docket 97-586.
*99(u) Final Report of the MPUC and the Maine
Attorney General regarding market power issues
raised by the prospect of retail competition
in the electric industry in Docket 97-877.
-44-
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K - Continued
*99(v) Order of the Federal Energy Regulatory
Commission dated December 22, 1998 in Docket
No. ER95-836-000.
(b) A Form 8-K was filed on: January 28, 1998, under item 5,
Other Events; June 3, 1998, under item 5, Other Events;
July 7, 1998, under item 5, Other Events; December 18,
1998, under item 5, Other Events and January 27, 1999,
under item 5, Other Events.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized, on the 19th of March, 1999.
MAINE PUBLIC SERVICE COMPANY
By: /s/ Larry E. LaPlante
Larry E. LaPlante
Vice President, Finance,
Administration and Treasurer
-45-
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 3/5/1999
(G. Melvin Hovey)
/s/Paul R. Cariani President and Director 3/5/1999
(Paul R. Cariani)
/s/Robert E. Anderson Director 3/5/1999
(Robert E. Anderson)
/s/Donald F. Collins Director 3/5/1999
(Donald F. Collins)
/s/D. James Daigle Director 3/9/1999
(D. James Daigle)
/s/Richard G. Daigle Director 3/5/1999
(Richard G. Daigle)
/s/J. Gregory Freeman Director 3/10/99
(J. Gregory Freeman)
/s/Deborah L. Gallant Director 3/5/1999
(Deborah L. Gallant)
/s/Nathan L. Grass Director 3/5/1999
(Nathan L. Grass)
/s/J. Paul Levesque Director 3/17/99
(J. Paul Levesque)
-46-
REPORT OF INDEPENDENT ACCOUNTANTS
To the Directors and Shareholders of
Maine Public Service Company
Our audits of the consolidated financial statements referred to in our
report dated February 12, 1999 appearing on page 15 of the 1998 Annual
Report to Shareholders of Maine Public Service Company (which report and
consolidated financial statements are incorporated by reference in this
Annual Report on Form 10-K) also included an audit of the financial
statement schedule in Item 14(a)(2) of this Form 10-K. In our opinion,
this financial statement schedule presents fairly, in all material
respects, the information set forth therein when read in conjunction
with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Portland, Maine
February 12, 1999
-47-
Maine Public Service Company & Subsidiary
Valuation of Qualifying Accounts & Reserves
For the Years Ended December 31, 1998, 1997, & 1996
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:
1998 215,000 181,360 129,022 310,382 215,000
1997 207,029 182,706 124,397 299,132 215,000
1996 214,130 182,000 102,627 291,728 207,029
-48-
Exhibit 13
Maine Public Service Company
The primary goal of Maine Public Service Company is to supply reliable,
economical electrical power to Northern Maine. The Company is an investor-owned
electric utility with a wholly-owned subsidiary, Maine and New Brunswick
Electrical Power Company, Ltd., located at Tinker, New Brunswick. Together both
companies provide energy to more than 35,000 retail customers in a 3,600 square
mile area.
Maine Public Service Company has a favorable mixture of generation sources
made up of power produced by hydro-electric and oil-fueled facilities, as well
as two independent wood-burning cogenerators. The system is strengthened by
electrical interconnections with New Brunswick, Canada, allowing electrical
support from the New Brunswick system and indirectly from the Hydro-Quebec
system.
Major business activities in the area center around the production of
agricultural and forest products. Service was provided at a high reliability
rate over the last year, and it is our aim to meet customer needs fully and
efficiently, at the lowest possible cost.
(Picture)
Customer Connection -- In December, 1998, MPS combined four district offices
into one centrally-located call center where service representatives quickly
focus on account information and respond to customers in a timely and efficient
manner. (Top: Russell Jandreau; Bottom, from left: Betty Harris, Rick Green,
Russell Jandreau, Francine Mosher, Gary Bell, Bev Wezner, Roxann Smith, and Glen
Leach.)
Table of Contents
Profile and Table of Contents 1
President's Letter 2-3
Analysis of Financial Condition
and Review of Operations -- 1998 4-13
Shareholder Information 13
Five-Year Summary of Selected Financial Data 14
Report of Independent Accountants 15
Financial Statements and Notes 16-31
Consolidated Financial Statistics 32-33
Consolidated Operating Statistics 34-35
Directors 36
Executive Officers and Stock
Transfer Information Inside Back 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@ mfx.net
(Pages 2 - 3)
President's Letter to our Shareholders and Employees
(Picture)
MPS To Sell Power Plants -- Maine Public Service Company agreed to sell its
electric generating assets to WPS Power Development, Inc., located in Green Bay,
Wisconsin. Both parties signed a purchase and sale agreement on July 7, 1998,
that has a price tag of $37.4 million for the utility's 91.8 megawatts of
generating capacity which is 3.2 times higher than the net book value of the
assets. Pictured, from left, are Keith Uffelman, WPS-PDI superintendent
engineering; Jerry Mroczkowski, WPS-PDI vice president; Paul Cariani, MPS
president; and Fred Bustard, MPS vice president of power supply and environment.
- ----------------
As we prepare to enter the new millennium, I am pleased to report that the
Company had earnings in 1998 of $1.39 per share, compared to a loss in 1997 of
$1.35. Although these earnings are by no means robust, they are certainly a
marked improvement over recent years.
Since 1995, the Company lost two of its largest customers which, along with
the closing of Maine Yankee Nuclear Plant, created serious financial
difficulties. Maine Yankee was very economical in the past, as well as our
largest source of supply, but had become a significant source of uncertainty and
risk. With these issues behind us, we await utility restructuring in a
healthier and more stable financial condition.
The fourth and final year of the Company's rate plan was to become effective
with at least a 3.1% rate increase on February 1, 1999. This rate increase has
been delayed, pending the outcome of the Company's sale of its generating
assets. If the Maine Public Utilities Commission (MPUC) approves the sale, the
Company will forego the rate increase; however, if the sale is not approved, the
Company will seek to increase rates as allowed under the rate plan.
In accordance with Maine law requiring divestiture, the Company agreed to sell
its generating assets to WPS Power Development, Inc. (WPS-PDI), a subsidiary of
WPS Resources Corporation of Green Bay, Wisconsin, at an agreed-upon price of
$37.4 million, subject to the approval of the MPUC. The sale price is 3.2 times
the net book value of the assets and includes all of the generating assets of
the Company, with the exception of our 5% interest in the Maine Yankee Nuclear
Power Plant.
We believe the generation asset sale is in the best interest of our customers
and shareholders, as it will reduce stranded costs revenue requirements by
approximately $19.9 million and stabilize rates for the remaining transmission
and distribution company.
The MPUC and the Attorney General's office have raised certain issues
concerning the development of an adequate retail market in northern Maine. All
power coming into northern Maine must come through the Province of New
Brunswick, Canada, and the major issue is transmission tariffs charged by New
Brunswick Power (NB Power). We believe these issues have been addressed through
an agreement with NB Power, the Office of the Public Advocate, and the electric
utilities in northern Maine. However, we cannot predict whether this agreement
with NB Power will satisfy the MPUC and Attorney General.
I am pleased to report that Maine Yankee has reached an agreement with
intervenors in the Federal Energy Regulatory Commission (FERC) rate case and
that an offer of settlement has been filed with the FERC. If the settlement is
approved by the FERC, it will resolve issues raised in the FERC proceeding,
including decommissioning cost issues and issues pertaining to prudence and the
decision to permanently close the plant. As part of the settlement, Maine
retail ratepayers will be held harmless from the amounts by which replacement
power costs for Maine Yankee, incurred between March 1, 2000 and December 31,
2004, exceed replacement power costs assumed in the report that served as the
basis for the plant shutdown decision, up to a maximum cumulative amount of $41
million. The Company's share of that maximum amount is $4.1 million.
Last year, we reported that a new marketing subsidiary was being developed and
that we were working with Cinergy, an electric utility headquartered in
Cincinnati, Ohio. Our alliance with Cinergy has not developed; however, we are
in the process of developing an alliance partnership with Engage Energy U.S.,
LLP. We are looking for our alliance partner to provide risk management and
financial resources in competitive electricity markets.
Our marketing subsidiary, Energy Atlantic, LLC (EA), initially will be
involved in retail and wholesale energy transactions in Maine. As a start-up
unregulated Company, EA is limited in the amount of capital, based upon
restrictions imposed not only by the MPUC, but also by your Board of Directors.
The Board, as well as the MPUC, has limited the capital contributions to a
maximum of $2 million, subject to the Company's ability to meet financial
covenants under its debt instruments.
Of the three Maine investor-owned utilities, MPS has the only unregulated
marketing subsidiary at this time. We feel there is an opportunity when the
market develops on March 1, 2000 in Maine and believe we can provide energy
products and services with the right partner.
Our marketing group has had success in reacquiring our largest wholesale
customer, Houlton Water Company, as of February 3, 1999; however, the marketing
subsidiary is expected to operate at a loss in 1999.
Economic development continues to occur in our service territory with a major
expansion taking place at McCain Foods, our largest customer and one of the
largest producers of french fries in the world. In addition, the opening of a
new lumber mill, along with a hardwood flooring operation, is expected to take
place in 1999.
There are many operational issues to consider as we move forward to a
restructured industry. In preparation for change, the Company opened its Call
Center in December, 1998, consolidating customer service from four districts
into one. The Call Center provides better and more efficient customer service.
In summary, we continue to make progress in our return to financial health.
Earnings have improved significantly and the sale of our generating assets will
put your Company in the best financial condition in more than twenty years.
Although not without some risk, we believe the settlement of the Maine Yankee
case is also in the best interest of our shareholders. Our new unregulated
marketing subsidiary (Energy Atlantic) is confident it can serve a portion of
the electric energy market in Maine when restructuring takes place on March 1,
2000. Continued economic development in our service territory will help our
regulated transmission and distribution utility maintain competitive rates. We
have positioned ourselves to meet successfully, and anticipate with eagerness
and enthusiasm, the advent of competition.
Thank you for the confidence and trust you have placed in me to lead us into
the twenty-first century. I would also like to thank our employees for their
innovation, teamwork, and support through these times of transition and rapid
change in our industry. Without the efforts and support of our employees, we
could not have made the progress we have seen in 1998.
Sincerely,
Paul R. Cariani
President and CEO
(Page 4)
Analysis of Financial Condition and Review of Operations - 1998
RESULTS OF OPERATIONS
Operating Revenues and Energy Sales
Consolidated operating revenues and MWH sales for the years 1998, 1997, and
1996 are as follows:
Consolidated Operating Revenues and Megawatt Hours Sold
(Dollars in Thousands) 1998 1997 1996
Dollars MWH Dollars MWH Dollars MWH
Residential $20,593 163,073 $20,391 167,368 $19,961 169,298
Commercial & Industrial
-Large 10,249 144,228 9,452 134,741 10,112 134,588
Commercial & Industrial
- Small 18,363 173,168 17,419 168,976 16,420 163,804
Other Retail 1,340 10,006 1,468 13,323 1,523 13,166
Total Retail 50,545 490,475 48,730 484,408 48,016 480,856
Sales for Resale 1,893 56,013 2,168 57,578 2,096 55,958
Total Primary 52,438 546,488 50,898 541,986 50,112 536,814
Secondary Sales 2,337 67,380 2,140 52,648 4,797 229,141
Total Sales of
Electricity 54,775 613,868 53,038 594,634 54,909 765,955
Other 1,852 2,034 2,355
Total Operating Revenues $56,627 $55,072 $57,264
Primary sales for 1998 were 546,488 MWH, which were approximately .8% and
1.8% higher than primary sales in 1997 and 1996, respectively. Retail sales for
1998 were 490,475 MWH, which were 6,067 MWH (1.3%) higher than 1997 and 9,619
MWH (2.0%) higher than 1996. Among the principle reasons for the increase in
retail sales was an increase of 9,487 MWH or 7.0% over 1997 large commercial and
industrial sales due to additional activity by food processors as well as lumber
and wood products customers. In addition, sales to small commercial and
industrial customers were 173,168 MWH in 1998, an increase of 4,192 MWH (2.5%)
and 9,364 MWH (5.7%) over sales in 1997 and 1996, respectively, primarily due
to the utilization of the former Loring AFB by small commercial customers.
Partially offsetting these retail sales increases were decreases in residential
sales of 2.6% and 3.7% from sales in 1997 and 1996, respectively, due to warmer
winters and loss of electric heat customers. Other retail sales in 1998 were
10,006 MWH, a 3,317 MWH decrease from 1997 due primarily to the aforementioned
utilization of the former Loring AFB.
During 1996 and 1997, the Company entered into long-term contracts with
five of its largest customers. In exchange for discounts from the Company's
standard rates, these customers agreed to purchase all of their electrical
requirements from the Company through the year 2000. All five of these
customers produced evidence of hardship to continue operations in the area or
were investigating self-generation, criteria that the Maine Public Utilities
Commission (MPUC) reviewed before approving these load-retention contracts.
Secondary sales for 1998 of $2,337,000 were $197,000 higher than sales in
1997 with the sale of all the Company's entitlement to the increased output of
Wyman Unit No. 4, 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. Secondary sales in 1996 reflect the sale
of the Company's entitlement to Maine Yankee, which was not available after 1996
with the plant's closure.
The MPUC has jurisdiction over retail rates. As more fully explained in
the "Regulatory Proceedings - Four-Year Rate Stabilization Plan" section of this
Annual Report, the MPUC approved the four-year rate plan effective January 1,
1996 with increases of 4.4%, 2.9% and 3.9% effective on January 1, 1996,
February 1, 1997, and February 1, 1998, respectively. The four-year rate plan
allows for annual increases in retail rates and eliminated the fuel clause.
Prior to the four-year rate plan, the Company had not sought a base rate
increase since November 1, 1992. The Company's rates are competitive among
investor-owned utilities in Maine and New England.
(Page 5)
The Federal Energy Regulator Commission (FERC) has jurisdiction over US
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
92.3% of normal production levels in 1998 and provided 18.8% of the Company's
energy needs. In 1997, hydro production was 80.7% of normal and provided 17.1%
of the Company's energy needs. Hydro production in 1996 was 126.5% of normal
and accounted for 21.1% of the Company's total energy supply. The availability
of low cost hydro reduces the need for more expensive sources of energy. As
more fully explained in the "Maine Yankee" section of this Annual Report,
following an economic analysis, the Maine Yankee Board of Directors voted on
August 6, 1997, to shut down the plant and begin decommissioning. During 1996,
Maine Yankee was restricted to 90% of rated capacity but was able to provide
31.1% of the Company's total energy supply, but did not operate after December
1996. To offset the loss of Maine Yankee production, the Company purchased
replacement energy from various sources, including, but not limited to, New
Brunswick Power (NB Power) in 1997, on a competitive basis. Beginning in
February 1998, Maine Yankee replacement power was purchased from Northeast
Empire in Ashland, Maine, in accordance with an agreement signed on December 19,
1997 that is effective until March 1, 2000. These purchases accounted for 56.3%
and 58.9% of the Company's energy supply in 1998 and 1997, respectively,
compared to 30.5% in 1996. The Company's oil-fired generating facilities
provided 5.4% of the Company's energy supply in 1998, compared to 4.2% in 1997
and 1.2% in 1996. In 1986, under an agreement ordered by the MPUC, the Company
began purchasing the output from an 17.6 MW wood-burning independent power
producer, currently owned by Wheelabrator-Sherman (W-S). As more fully
explained in the "Regulatory Proceedings - Restructured Agreement with
Wheelabrator-Sherman" section of this Annual Report, the Company and W-S have
agreed on a restructured purchase power arrangement. These mandated purchases
from this facility represented 19.5% of the Company's energy supply in 1998
compared to 19.8% and 16.1% in 1997 and 1996, respectively.
Electric Output By Sources
(Percent)
1998 1997 1996
Oil 5.4 4.2 1.2
Cogeneration 19.5 19.8 16.1
Purchases 56.3 58.9 30.5
Nuclear - - 31.1
Hydro 18.8 17.1 21.1
Total 100.0 100.0 100.0
Operating Expenses
For the three-year period 1996-1998, purchased power expenses are as
follows:
(Dollars in Thousands)
1998 1997 1996
Wheelabrator-Sherman $13,830 $15,911 $15,593
Maine Yankee 5,670 12,303 10,185
NB Power 4,562 10,786 3,498
Northeast Empire 7,160 - -
System Purchases 530 1,308 2,544
Total Purchased Power 31,752 40,308 31,820
Deferred Fuel (2,234) (3,699) (1,375)
Net Purchased Power $29,518 $36,609 $30,445
Purchased power expenses from Wheelabrator-Sherman (W-S) were $13,830,000,
a $2,081,000 or 13.1% decrease from 1997. As discussed in the "Regulatory
Proceedings - Restructured Agreement with Wheelabrator-Sherman" section of this
Annual Report, W-S agreed to reductions in the price of purchased power
beginning May, 1998. The decreased W-S rate in 1998 was partially offset by a
1.9% increase in output. For 1998, 1997, and 1996, these mandated purchases
from W-S represented 43.6%, 39.5%, and 49.0%, respectively, of total purchased
power expenses. As more fully explained in the "Maine Yankee" section of this
Annual Report, Maine Yankee has been out of service since December, 1996 and
closed permanently in August, 1997. As part of a rate stipulation approved by
the Maine Public Utilities Commission on January 30, 1998, the Company agreed
to a 1997 write off of $1.5 million of deferred capacity charges related to the
1997 Maine Yankee refueling. The increase in 1997 Maine Yankee expenses also
reflects the efforts to restart the plant in early 1997. In 1998, as the plant
prepared for decommissioning, Maine Yankee expenses were $5,670,000, a decrease
of $6,633,000 compared to 1997. The Company purchased replacement energy
primarily from NB Power in 1997 and, as discussed in the "Energy Supply" section
of this Annual Report, began purchasing replacement power from Northeast Empire
in Ashland, Maine, in February 1998. Purchases in 1998 from NB Power and the
Northeast Empire totaled $11,722,000, an increase of $936,000 over the
replacement power in 1997. System purchases were $530,000 in 1998, a decrease
of $778,000 and $2,014,000 from 1997 and 1996, respectively, due to decreased
power marketing activities, as discussed in the "Operating Revenues and Energy
Sales" sections of this Annual Report. Deferred fuel expense, a component of
purchased power, was a negative $2,234,000 in 1998, compared to a negative
$3,699,000 in 1997 and a negative $1,375,000 in 1996. Negative deferred fuel
indicates expenses deferred to a future period when these costs will be
collected in rates. As more fully discussed in the "Regulatory Proceedings -
Four-Year Rate Stabilization Plan" section of this Annual Report, the Company
is allowed an annual deferral of $1.5 million of W-S fuel expenses, as well as
one-half of the Maine Yankee replacement power costs, offset by the savings from
the amended purchased power agreement with W-S. The sharing mechanism for the
Maine Yankee replacement power went into effect on June 6, 1997, with
approximately $3.5 million deferred through the end of 1998, subject to future
collection.
(Page 6)
Other operation and maintenance expenses for the three-year period are as
follows:
(Dollars in Thousands)
1998 1997 1996
Generation
Fuel Expense $ 896 $ 893 $ 387
Other 1,237 1,321 1,571
2,133 2,214 1,958
Transmission and
Distribution 3,614 3,609 4,228
Customer Accounting and
General Administrative 7,221 6,947 7,629
Total $12,968 $12,770 $13,815
Fuel expenses for generation increased in 1998 and 1997 compared to 1996
because of increased generation at Wyman Unit No. 4, an oil-fired generating
facility. Other generation expenses were $1,237,000 in 1998, a decrease of
$84,000 and $334,000 from 1997 and 1996, respectively, reflecting reduced
activity at the Company's Steam Plant in Caribou, Maine, which has been on
inactive status since January 1996. Transmission and distribution expenses
were $3,614,000 in 1998, which were comparable to 1997. An increase in
tree-trimming expenses of $224,000 was offset by a decrease in wheeling expenses
due to the termination of a wheeling agreement with NB Power. Transmission and
Distribution expenses were higher in 1996 than 1998 and 1997, reflecting the
increased power marketing-related wheeling expenses with the sale of Maine
Yankee production. Customer accounting, and general and administrative expenses
increased by $274,000 from $6,947,000 in 1997 to $7,221,000 in 1998, but were
$408,000 less than 1996 expenses of $7,629,000. Interest expenses for 1998,
1997, and 1996 were $4,327,000, $3,583,000, and $3,530,000, respectively.
Interest on additional short-term borrowings required for Maine Yankee
replacement power costs is the principle reason for the increase in 1998, as
well as interest recognized on the open access transmission refund and FAME
financing costs.
Maine Yankee
The Company owns 5% of the Common Stock of Maine Yankee, which operated an 860
MW nuclear power plant (the "Plant") in Wiscasset, Maine. On August 6, 1997,
the Board of Directors of Maine Yankee voted to permanently cease power
operations and to begin decommissioning the Plant. The Plant experienced a
number of operational and regulatory problems and did not operate after December
6, 1996. The decision to close the Plant permanently was based on an economic
analysis of the costs, risks and uncertainties associated with operating the
Plant compared to those associated with closing and decommissioning it. The
Plant's operating license from the Nuclear Regulatory Commission (NRC) was due
to expire on October 21, 2008.
The Maine Public Utilities Commission (MPUC) stayed an investigation of the
prudency of the shutdown decision and the operation of Maine Yankee prior to the
shutdown decision, pending the outcome of Maine Yankee's rate case before the
Federal Energy Regulatory Commission (FERC). The MPUC and the Maine Office of
the Public Advocate (OPA) are actively participating in the FERC proceeding, as
well as 28 municipal and cooperative utilities in New England who received
approximately 6.2% of the output from Maine Yankee (the "Secondary Purchasers").
In support of its request for an increase in decommissioning collections,
Maine Yankee submitted with its initial FERC rate case filing a 1997
decommissioning cost study performed by TLG Services, Inc. ("TLG"). During
1998, Maine Yankee engaged in an extensive competitive bid process to engage a
Decommissioning Operations Contractor ("DOC") to perform certain major
decontamination and dismantlement activities at the Plant on a fixed-price,
turnkey basis. As a result of that process, a consortium headed by Stone &
Webster Engineering Corporation ("Stone & Webster") was selected to perform such
activities under a fixed-price contract. The contract provides for, among other
undertakings, construction of an independent spent fuel storage installation
("ISFSI") and completion of major decommissioning activities and site
restoration by the end of 2004. The DOC process resulted in fixing certain
costs that had been estimated in the earlier decommissioning cost estimate
performed by TLG.
Since the filing of the FERC rate request, Maine Yankee and the active
intervenors, including among others the MPUC Staff, the OPA, the Company and
other owners, the Secondary Purchasers, and a Maine environmental group (the
"Settling Parties"), engaged in extensive discovery and negotiations. Those
parties participated in settlement discussions that resulted in an Offer of
Settlement filed by those parties with the FERC on January 19, 1999. On
February 8, 1999, the FERC Trial Staff recommended that the presiding judge
certify the settlement to the FERC and that the FERC approve it. Upon approval
by the FERC, the settlement would constitute a full settlement of all issues
raised in the consolidated FERC proceeding, including decommissioning-cost
issues and issues pertaining to the prudence of the management, operation, and
decision to permanently cease operation of the Plant. A separately negotiated
settlement filed with the FERC on February 5, 1999 would resolve the issues
raised by the Secondary Purchasers by limiting the amounts they will pay for
decommissioning the Plant and by settling other points of contention affecting
individual Secondary Purchasers.
The Offer of Settlement provides for Maine Yankee to collect $33.6 million in
the aggregate annually, effective January 15, 1998 consisting of: (1) $26.8
million for estimated decommissioning costs, and (2) $6.8 million for
ISFSI-related costs. The original filing with FERC on November 6, 1997, called
for an aggregate annual collection rate of $36.4 million for decommissioning and
the ISFSI, based on the TLG estimate. Under the settlement the amount collected
annually could be reduced to approximately $26 million if Maine Yankee is able
to (1) use for construction of the ISFSI funds held in trust under Maine law for
spent-fuel disposal, and (2) access approximately $6.8 million being held by the
State of Maine for eventual payment to the State of Texas pursuant to a compact
for low-level nuclear waste disposal, the future of which is now in question
after rejection of the selected disposal site in west Texas by a Texas
regulatory agency. Both would require authorizing legislation in Maine, which
Maine Yankee is committed to use its best efforts to obtain.
The Offer of Settlement also provides for recovery of all unamortized
investment (including fuel) in the Plant, together with a return on equity of
6.50 percent, effective January 15, 1998, on equity balances up to certain
maximum allowed equity amounts. The Settling Parties also agreed in the
proposed settlement not to contest the effectiveness of the Amendatory
Agreements submitted to FERC as part of the original filing, subject to certain
limitations including the right to
(Page 7)
challenge any accelerated recovery of unamortized investment under the terms of
the Amendatory Agreements after a required informational filing with the FERC
by Maine Yankee.
As a separate part of the Offer of Settlement, the Company, Central Maine
Power Company, and Bangor Hydro-Electric Company (the other two Maine owners of
Maine Yankee), the MPUC Staff, and the OPA entered into a further agreement
resolving retail rate issues and other issues specific to the Maine parties,
including those that had been raised concerning the prudence of the operation
and shutdown of the Plant (the "Maine Agreement"). Under the Maine Agreement,
the Company would continue to recover its Maine Yankee costs in accordance with
its most recent Rate Stabilization Plan ("RSP") order from the MPUC without any
adjustment reflecting the outcome of the FERC proceeding. To the extent that
the Company has collected from its retail customers a return on equity in excess
of the 6.50 percent contemplated by the Offer of Settlement, no refunds would
be required, but such excess amounts would be credited to the customers to the
extent required by the RSP.
The final major provision of the Maine Agreement requires the Maine owners,
for the period from March 1, 2000 through December 1, 2004, to hold their Maine
retail ratepayers harmless from the amounts by which the replacement power costs
for Maine Yankee exceed the replacement power costs assumed in the report to the
Maine Yankee Board of Directors that served as a basis for the Plant shutdown
decision, up to a maximum cumulative amount of $41 million. The Company's share
of that maximum amount would be $4.1 million for the period. The Maine
Agreement, which was approved by the MPUC on December 22, 1998 also sets forth
the methodology for calculating such replacement power costs.
The Company believes the Offer of Settlement, including the Maine Agreement,
reasonably resolves the issues presented by the parties in the Maine Yankee FERC
proceeding. If the Offer of Settlement is approved by the FERC, several
significant uncertainties regarding the recovery of Maine Yankee-related costs
are eliminated. Although all of the active parties to the proceeding have
agreed to support or, with respect to certain individual provisions, not oppose,
the Offer of Settlement, the Company cannot predict with certainty whether or
in what form the Offer of Settlement will be approved by the FERC.
With the closing of Maine Yankee, a provision of the Company's rate plan
allowing the deferral of 50% of the Maine Yankee replacement power costs went
into effect on June 6, 1997. For 1998, Maine Yankee replacement power costs
were offset by net savings from the restructured Purchase Power Agreement with
Wheelabrator-Sherman, in accordance with the rate plan stipulation, resulting
in a deferral of $1.1 million. As of December 31, 1998, the Company has a
deferred Maine Yankee replacement power cost balance of approximately $3.5
million, subject to recovery in accordance with the rate plan.
The February 1, 1998, rate increase included $562,000 of the recoverable 1997
Maine Yankee replacement power costs with the remaining costs to be included in
the rate plan increase in 1999.
On September 1, 1997, Maine Yankee estimated the sum of the future payments
for the closing, decommissioning and recovery of the remaining investment in
Maine Yankee to be approximately $930 million, of which the Company's 5% share
would be approximately $46.5 million. In December, 1998, Maine Yankee updated
its estimate of decommissioning costs based on the Settlement, as discussed
above. Legislation enacted in Maine in 1997 calls for restructuring the
electric utility industry and provides for recovery of decommissioning costs,
to the extent allowed by federal regulation, through the rates charged by the
transmission and distribution companies. Based on the Maine legislation and
regulatory precedent established by the FERC in its opinion relating to the
decommissioning of the Yankee Atomic nuclear plant, the Company believes that
it is entitled to recover substantially all of its share of such costs from its
customers and, as of December 31, 1998, is carrying on its consolidated balance
sheet a regulatory asset and a corresponding liability in the amount of $36.0
million, which is the September, 1997 cost estimate of $46.5 million discussed
above reduced by the Company's post-September 1, 1997 cost-of-service payments
to Maine Yankee and reflects the cost adjustments agreed to in the Settlement.
Earnings and Dividends
For 1998, the earnings per share were $1.39 based on net income available
for Common Stock of $2,252,915. For 1997, the loss per share was $1.35 based
on a loss of $2,177,137. Earnings per share in 1996 were $1.31 based on net
income available for Common Stock of $2,110,694. The average shares outstanding
for all three years were 1,617,250.
Earnings for the three-year period were impacted by the operations and
eventual closing of Maine Yankee. As discussed in the "Maine Yankee" section
of this Annual Report, the plant did not operate during 1998 and 1997 and was
shut down permanently in August 1997. For 1997, the related replacement power
and increased capacity expenses to restart the plant reduced earnings by $2.94
per share compared to 1996. However, the earnings in 1998 improved by $2.66 per
share when Maine Yankee began the process of decommissioning.
The Company's return on equity for 1998 was 6.51% compared to a negative
6.02% for 1997 and 5.48% for 1996. After completion of the generating asset
sale, the return on equity is expected to increase to targeted levels.
The dividends paid in 1998 were $1.00 per share. Your Board of Directors
reduced the quarterly dividend from $.46 to $.25 per share effective for the
April 1, 1997 payment. The dividends paid in 1997 and 1996 were $1.21 and $1.84
per share, respectively. The dividend reduction, along with other actions to
control expenditures, was required to improve the Company's cash flows in
response to the difficulties at Maine Yankee. For additional information, see
the "Liquidity" section of this Annual Report.
Liquidity
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.
The restructuring of the amended power purchase agreement with
Wheelabrator-Sherman Energy Company (W-S) as more fully discussed later in the
"Capital Resources" section of this Annual Report was the most significant
financial activity in 1998. Net cash flows used for operating activities for
1998 were $2.1 million, which includes the $8.7 million payment to W-S under
The terms of the new agreement. To
(Page 8)
finance this payment to W-S, the Company issued $11.5 million of long-term debt
through the Finance Authority of Maine (FAME) with $2.4 million held in escrow
in accordance with the loan agreement with FAME and the remaining proceeds used
for financing costs. During 1998, the Company made the final sinking fund
payment on the 7 1/8% series of first mortgage bonds of $2.9 million, as well
as $1.3 million in sinking fund payments for a total of $4.2 million in
long-term debt retirements. During 1998, the Company paid $2 million in
dividends and spent $3.7 million for electric plant. The Company also withdrew
$1.9 million from the proceeds held in trust from the 1996 tax-exempt bond
issuance and had additional short-term borrowings of $900,000. As of December
31, 1998, the Company has approximately $400,000 remaining in the tax-exempt
bond trust fund to be used for the construction of qualifying property.
In 1997, the additional replacement power and capacity expenses to restart and
subsequently to close and start decommissioning Maine Yankee significantly
reduced the Company's earnings and cash flows. As a result, the Company had to
increase short-term borrowings by $5,800,000 to fund operating and construction
activities and pay dividends. The Company also withdrew $2.0 million from
proceeds held in trust from the 1996 tax-exempt bonds, based on qualifying
property additions. As of December 31, 1997, $2.3 million remained in trust to
be withdrawn by June 1999. Net cash flows used in operating activities were
$1.7 million. The Company paid dividends of $1.2 million, made debt payments
of $1.3 million, and invested $2.7 million in electric plant.
In 1996, net cash flows generated from operating activities were $7.4 million.
During 1996, $15 million in tax-exempt bonds were issued with the proceeds used
to refund a $10 million series of tax-exempt bonds issued in 1991. The
remaining $5 million of proceeds were deposited with the trustee to be withdrawn
based on qualifying property additions and eligible issuance costs. During
1996, the Company withdrew $1.1 million from these proceeds, paid dividends of
$3 million, made additional long-term debt payments of $1.3 million and invested
$3.4 million in electric plant. During 1996, the Company did not require any
additional short-term borrowings to meet working capital requirements.
For additional information regarding construction expenditures for 1996 to
1998 and anticipated construction expenditures for 1999, see Note 10,
"Commitments, Contingencies, and Regulatory Matters - Construction Program", of
the Notes to Consolidated Financial Statements.
To satisfy working capital requirements, the Company uses short-term
borrowings from its revolving credit agreement. At the end of 1998, the Company
had $8.1 million of short-term debt compared to $7.2 million and $1.4 million
at the end of 1997 and 1996, respectively. During 1996 to 1998, the interest
rates on these short-term borrowings were below the existing prime rate. For
additional information on the short-term credit facility, see Note 5,
"Short-Term Credit Arrangement", of the Notes to Consolidated Financial
Statements. Based on current projections, the Company estimates that operating
cash flows will be sufficient to cover its other sinking fund payments,
construction activities, and other financial obligations.
Capital Resources
After several years of negotiations, the Company has restructured its Power
Purchase Agreement (PPA) with the Wheelabrator-Sherman Energy Company (W-S)
under which the Company is obligated to purchase the entire output (up to
126,582 MWH) of a 17.6 MW biomass plant owned by W-S. The original term of the
PPA ran through December 31, 2000 and could be renewed by either party for an
additional fifteen years at prices to be determined by mutual agreement or,
absent mutual agreement, by the MPUC.
On October 15, 1997, the Company and W-S agreed to amend the PPA. Under the
terms of this amendment, W-S agreed to reductions in the price of purchased
power of approximately $10 million over the PPA's current term. The Company and
W-S also agreed to renew the PPA for an additional six years at agreed-upon
prices. The Company made an up-front payment to W-S of $8.7 million on May 29,
1998, with the financing provided by the Finance Authority of Maine (FAME).
This payment has been reflected as a regulatory asset and, based on an MPUC
order, will be included in stranded costs and will be recovered in the rates of
the transmission and distribution utility. The Company believes the amended PPA
will help relieve the financial pressure caused by the recent closure of Maine
Yankee as well as the need for substantial increases in its retail rates, and
is therefore, in the best interests of the Company, its customers and
shareholders.
On May 29, 1998, FAME issued $11,540,000 of its Taxable Electric Rate
Stabilization Revenue Notes, Series 1998A (Maine Public Service Company) (the
"Notes") on behalf of the Company. The Notes were issued pursuant to, and are
secured under, a Trust Indenture by and between FAME and Peoples Heritage Bank,
Portland, Maine, as Trustee (the Trustee), for the purpose of: (i) financing
the up-front payment to Wheelabrator-Sherman of approximately $8.7 million, as
required under an amended purchase power agreement; (ii) for the Capital Reserve
Fund, as required by FAME under their Electric Rate Stabilization Program; and
(iii) for issuance costs. The Notes are limited obligations of FAME, payable
solely out of the trust estate available under the Indenture, principally the
Loan Note and Loan Agreement with the Company and the Capital Reserve Fund held
by the Trustee. The Company has issued $4 million of its first mortgage bonds
and $7.54 million of its second mortgage bonds as collateral for its performance
under the Loan Note issue pursuant to the Loan Agreement. The Notes will bear
interest at a Floating Interest Rate, initially at 5.7% per annum, and will be
adjusted weekly. On June 1, 1998, the Company purchased an interest rate cap
of 7% at a cost of $172,000, to expire June, 2008, to limit its interest rate
exposure to quarterly U.S. LIBOR rates. At the end of 1998, the cumulative
effective interest rate, including issuance costs and credit enhancement fees,
since issuance for this series was 6.58%.
On June 19, 1996, the Maine Public Utilities Financing Bank (MPUFB) issued $15
million of its tax-exempt bonds, due April 1, 2021 (the 1996 Series) on behalf
of the Company. The proceeds of the new 1996 Series were used to refund the $10
million 1991 tax-exempt Series through the payment of a refunding note from
Fleet Bank of Maine and provided $5 million for the acquisition of qualifying
property. Pursuant to the long-term note issued under a loan agreement between
the Company and the MPUFB, the Company has agreed to make payments to the MPUFB
for the principal and interest on the bonds. Concurrently, pursuant to a
letter of credit and reimbursement agreement, the Company caused a Direct Pay
Letter of Credit for an initial term of three years to be issued by The Bank of
New York for the benefit of the holders of such bonds. To secure the Company's
obligations under the letter of credit and reimbursement agreement, the Company
issued a second mortgage bond to The Bank of New York, as Agent, under the
reimbursement agreement, in the amount of $15,875,000. The Company has the
option of selecting weekly, monthly, annual or term interest rate periods for
the 1996 Series. The
(Page 9)
initial interest period selected by the Company was weekly, and the initial
weekly interest rate was 3.75% per annum. At the end of 1998, the cumulative
effective interest rate, including issuance costs and credit enhancement fees,
since issuance for this series was 5.85%.
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 articles of incorporation authorized
the issuance of 200,000 shares of Preferred Stock with the par value of $100 per
share and 200,000 shares of Preferred Stock with the par value of $25 per share.
The Company can also issue first mortgage bonds of $4.5 million and second
mortgage bonds of $11.3 million without bondable property additions.
In order to maintain the Company's common equity at levels appropriate for an
investor-owned utility, the Company has repurchased 250,000 shares at a cost of
$5,714,376. The original five-year program approved by the MPUC expired in
September 1994. On November 1, 1994, the MPUC approved the Company's
application to repurchase up to an additional 300,000 shares over a five-year
period. With the write-offs required by the rate plan and the operating loss
in 1997, the Company did not use the program to adjust its capital structure.
However, with the pending generating asset sale, the Company may be required to
adjust its capital structure depending on decisions by the MPUC in the Company's
rate design and stranded cost recovery cases.
In early 1997, in anticipation of a lengthy and expensive outage to restart
Maine Yankee, the Company obtained amendments to the short-term revolving credit
agreement and the letter of credit supporting the 1996 series of tax-exempt
bonds. These amendments, dated March 28, 1997, modified interest coverage tests
to exclude Maine Yankee incremental replacement power costs through September
30, 1997. Under the amendment to the revolving credit agreement, the Company
was obligated to issue a first mortgage bond of $11 million by May 15, 1997 as
collateral for the maximum amount of its obligations under the agreement. After
receiving approval from the MPUC on April 28, 1997, the Company issued bonds on
May 5, 1997. As discussed in the "Maine Yankee" section of this Annual Report,
the Maine Yankee owners subsequently voted to close the nuclear power plant and
start decommissioning. However, the previously mentioned amendments did not
cover additional Maine Yankee replacement and capacity expenses in the fourth
quarter of 1997, and the Company was not able to attain its interest coverage
tests. On March 12, 1998, the Company and the Banks executed a waiver of the
interest coverage tests for the fourth quarter of 1997, avoiding a default. On
March 31, 1998, the Company and the Banks executed amendments to the revolving
credit agreement and letter of credit and reimbursement agreement which further
adjusts the interest coverage tests for the first three quarters of 1998. With
these amendments, the Company has achieved its amended interest coverage tests
for the first three quarters of 1998. For the fourth quarter of 1998, the
interest coverage tests, as prescribed in the underlying documents without
amendment, were also achieved by the Company. The revolving credit agreement
was temporarily increased by an additional $3 million until June 30, 1999 with
the issuance of $2 million of first mortgage bonds. The additional borrowing
capacity will not be needed with the expiration of this temporary increase. In
addition, the revolving credit agreement and letter of credit supporting the
tax-exempt bonds due 2021 were extended by one year to October, 1999 and June,
2000, respectively.
As discussed in the "Regulatory Proceedings- Industry Restructuring" section
of this Annual Report, the pending sale of the Company's generating assets will
significantly impact the Company's capital structure. The Company has proposed
that the net gain from the sale be used to reduce stranded costs revenue
requirements by approximately $19.9 million. Although the impact of the sale
will not be immediately reflected in earnings, the after-tax proceeds from
the sale and the liquidation of the Canadian subsidiary totalling an estimated
$24 million will be used to reduce long-term debt, which will in turn reduce
future interest costs.
Employees
At the end of 1998, the Parent Company had 155 full-time employees compared
to 149 for 1997. The Subsidiary had 9 full-time employees for 1998 and 1997.
Consolidated payroll costs were $6.6 million for 1998 and $6.5 million for 1997.
Local 1837 of the International Brotherhood of Electrical Workers ratified a
three-year contract with the Parent Company, effective on October 1, 1996. The
agreement included a 2.9% wage increase in the first year and a 2.75% increase
in each of the last two years of the contract.
The Subsidiary and Local 1733 of the International Brotherhood of Electrical
Workers ratified a one-year contract extension effective January 1, 1999. The
new agreement includes a wage increase of 2.75% for calendar year 1999. A
one-year extension for calendar year 1998 included a 1.93% wage increase. The
three-year contract that expired December 31, 1997 had allowed annual wage
increases of 3.75%.
Regulatory Proceedings
Industry Restructuring
On May 29, 1997, legislation titled "An Act to Restructure the State's
Electric Industry" was signed into law by the Governor of Maine. The principal
provisions with accounting impact on the Company are as follows:
1. Beginning on March 1, 2000, all consumers of electricity have the right
to purchase generation services directly from competitive electricity
suppliers who will not be subject to rate regulation.
2. By March 1, 2000, the Company, Central Maine Power Company (CMP), and
Bangor Hydro-Electric Company (BHE) must divest themselves of all
generation related assets and business functions except for:
a) contracts with qualifying facilities, such as the Company's power
contract with Wheelabrator-Sherman (W-S), and conservation providers;
b) nuclear assets, namely, the Company's investment in the Maine Yankee
Atomic Power Company;
c) facilities located outside the United States, i.e., the Company's
hydro facility in New Brunswick, Canada; and
(Page 10)
d) assets that the MPUC determines necessary for the operation of the
transmission and distribution services. The MPUC can grant an
extension of the divestiture deadline if the extension will improve
the selling price. For assets not divested, the utilities are
required to sell the rights to the energy and capacity from these
assets. For more information about the Company's pending sale of its
generating assets, see "Generating Asset Sale" section in this Annual
Report.
3. The Company will continue to provide transmission and distribution
services which will be subject to continued rate regulation by the MPUC.
4. Maine electric utilities will be permitted a reasonable opportunity to
recover legitimate, verifiable and unmitigable costs that are otherwise
unrecoverable as a result of retail competition in the electric utility
industry (so-called "stranded costs"). The MPUC shall determine these
stranded costs by considering:
a) the utility's regulatory assets related to generation, i.e., the
Company's unrecovered Seabrook investment;
b) the difference between net plant investment in generation assets
compared to the market value for those assets; and
c) the difference between future contract payments and the market value
of the purchased power contracts, i.e., the W-S contract.
By the end of 1999, the MPUC will have estimated the stranded costs
for the Company and the manner for the collection of these costs by the
transmission and distribution company. Customers reducing or eliminating
their consumption of electricity by switching to self-generation,
conversion to alternative fuels or utilizing demand-side management
measures cannot be assessed exit or entry fees.
The Company estimates its stranded costs to be approximately $99.3
million, based on its February 9, 1999 filing, which included the remaining
investment in Seabrook, the estimated above-market costs of the amended
power purchase agreement and recovery of fuel expense deferrals related to
W-S, the obligation for the remaining operating expenses and recovery of
the Company's remaining investment in Maine Yankee, and the recovery of
several other regulatory assets, but does not include any benefits from
the Company's sale of generating assets.
5. The MPUC shall include in the rates to be charged by the transmission and
distribution utility decommissioning expenses for Maine Yankee. In 2003,
and every three years thereafter until the stranded costs are recovered,
the MPUC shall review and adjust the stranded cost recovery amounts and
related transition charges. However, the MPUC may adjust the amounts at
any point in time that they deem appropriate. Since the legislation
provides for our recovery of stranded costs by the transmission and
distribution company, the Company will continue to recognize existing
regulatory assets and plant costs as provided by Emerging Issues Task Force
97-4 "Deregulation of the Pricing of Electricity" (EITF 97-4).
6. Billing and metering services will be subject to competition beginning
March 1, 2002, but permits the MPUC to establish an earlier date, no sooner
than March 1, 2000.
7. All competitive providers of retail electricity must be licensed and
registered with the MPUC and meet certain financial standards, comply with
customer notification requirements, adhere to customer solicitation
requirements and are subject to unfair trade practice laws. Competitive
electricity providers must have at least 30% renewable resources in their
energy portfolios, including hydro-electric generation.
8. A standard-offer service will be available, ensuring access for all
customers to reasonably priced electric power. Unregulated affiliates of
CMP and BHE providing retail electric power are prohibited from providing
more than 20% of the load within their respective service territories under
the standard offer service, while any unregulated affiliate of the Company
does not have a similar restriction.
9. Employees other than officers, displaced as a result of retail competition
will be entitled to certain severance benefits and retraining programs.
These costs will be recovered through charges collected by the regulated
transmission and distribution company.
The MPUC will conduct several rulemaking proceedings associated with the new
restructuring law. The Company is presently reviewing its business operations
and the opportunities that the new restructuring law presents.
In accordance with EITF 97-4 when all of the details of the restructuring plan
are determined by the MPUC rulemaking, the Company will discontinue application
of the Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting
for the Effects of Certain Types of Regulations", for the generating segment of
its business jurisdiction. As a result, the Company continues to defer certain
costs as regulatory assets in instances where recovery through future regulatory
cash flows is anticipated.
Generating Asset Sale
On July 7, 1998, the Company and WPS Power Development, Inc. (WPS-PDI) signed
a purchase and sale agreement for the Company's electric generating assets.
WPS-PDI agreed to purchase 91.8 megawatts of generating capacity for $37.4
million, which is 3.2 times higher than the net book value of the assets. This
sale of assets is required by the State's electric industry restructuring law
and requires the approvals of the MPUC and the FERC. The gain from the asset
sale would reduce stranded costs revenue requirements by $19.9 million.
On August 7, 1998, the Company filed with the MPUC for approval of this sale.
The proceeding was given the Docket No. 98-584. The Public Advocate and the
Houlton Water Company (HWC) have intervened in this proceeding. The MPUC, in
its order approving the Company's divestiture plan in MPUC Docket No. 97-670,
noted a number of concerns that it would address in Docket No. 98-584.
Principal among these concerns is whether the Company's lack of any connection
to New England electrical markets, except through the Province of New Brunswick,
Canada (NB), and the transmission
(Page 11)
system owned by the Maine Electric Power Company (the MEPCO line), presented
unique issues concerning development of an adequate competitive retail market
for electricity in northern Maine and directed the Company to address these
concerns when it filed for approval in Docket No. 98-584.
On January 29, 1999, the Company filed a Partial Stipulation in this Docket.
Under the terms of this Stipulation, the parties agreed that access to northern
Maine's electrical markets exclusively through the transmission of the New
Brunswick Power Corporation (NB Power) and the MEPCO line "is no longer a
substantial barrier to the development of an adequate retail market for
electricity in northern Maine" and that any market power issues in northern
Maine should not prevent the MPUC from approving the sale of the Company's
generation assets to WPS-PDI.
The basis for this Stipulation is a Products and Service Agreement between NB
Power, on the one hand, and the Company, HWC, Eastern Maine Electric
Cooperative, Inc., and the Van Buren Light and Power District (collectively,
"the northern Maine utilities"), on the other. This Agreement is based in large
part upon the recommendations of the Final Report of the Maine Attorney General.
Under this Agreement, NB Power agrees to supply: (i) tie-line interruption
service, on a firm or non-firm basis, to any northern Maine utility requiring
it; (ii) ancillary services to any northern Maine utility; (iii) transmission
services through NB to any northern Maine utility at a fixed rate that can be
increased only by authorization of the proper NB regulatory authority; and (iv)
bona fide offers of energy and capacity and other electric products and service
to any customer of any northern Maine utility. It is understood that northern
Maine utilities will transfer these services at cost to competitive electricity
providers.
Four-Year Rate Stabilization Plan
On November 13, 1995, the Maine Public Utilities Commission (MPUC) approved
a stipulation signed by the Company, the Commission Staff, and the Office of the
Public Advocate (OPA). 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 rate plan, as amended in January, 1998, which applies
cost of service principles, the Company's retail rates were increased by 4.4%,
2.9%, and 3.9% on January 1, 1996, February 1, 1997 and February 1, 1998,
respectively. 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 rate
plan also provides for adjustments resulting from the operation of a
profit-sharing mechanism, as well as provisions for mandated costs and plant
outage provisions, particularly the shutdown of Maine Yankee, as further
explained in the "Maine Yankee" section of this Annual Report.
The Company was also permitted to defer $1,500,000 annually of the costs of
its purchases from Wheelabrator-Sherman during each of the four years of the
rate plan. The plan permits the Company to recover this deferred amount, up to
a total of $6,000,000, in rates beginning in the year 2001. The rate plan
provides for the deferral until the year 2000, of approximately $1.3 million,
net of income taxes, of uncollected retail fuel at the beginning of the rate
plan, while an additional $300,000, net of income taxes, will be collected in
rates over the rate plan period.
On January 26, 1998, the MPUC approved a 3.9% February 1, 1998 rate increase,
according to terms of a stipulation agreed to by the Company and the OPA, with
the support of the MPUC staff. The principal elements of the agreement are as
follows:
1. The rate increase effective February 1, 1998 was 3.9% consisting of
the specified increase of 2.75% and approximately $562,000 of the 1997
recoverable Maine Yankee replacement power costs (1.15%);
2. The minimum rate increase effective February 1, 1999, consisting of
a specified increase of 2.0% and the remaining recoverable 1997 Maine
Yankee replacement power costs of $523,000;
3. Maine Yankee replacement power costs for the period October 1, 1997
through September 30, 1998 will be offset by the 1998 savings under
the restructured Wheelabrator-Sherman contract (see "Restructured
Agreement with Wheelabrator-Sherman" below) with the recovery of any
incremental Maine Yankee replacement power costs subject to a final
order by the MPUC in its review of the prudency of closing Maine
Yankee;
If the MPUC approved the sale of generating assets in the first quarter of
1999, the Company would agree to not increase customer rates in 1999, originally
scheduled for February 1, 1999, in accordance with the rate plan stipulation.
Instead, the Company has requested that a portion of the gain on the sale be
used to achieve its revenue requirement.
Restructured Agreement with Wheelabrator-Sherman
For several years, the Company negotiated the restructuring of the terms of
its current Power Purchase Agreement (PPA) with Wheelabrator-Sherman (W-S). The
Company was ordered into the PPA by the MPUC in 1986, which required the
purchase of the entire output (up to 126,582 MWH) of a 17.6 MW biomass plant
through December 31, 2000. Under the earlier agreement, either party could
renew the agreement for an additional fifteen years at prices to be determined
by mutual agreement, or absent mutual agreement, by the MPUC. By agreement
dated October 15, 1997, the Company and W-S amended the PPA.
Under the terms of this amendment, W-S agreed to reductions in the price of
purchased power of approximately $10 million over the PPA's current term in
exchange for an up-front payment of $8.7 million. The Company and W-S also
agreed to renew the PPA for an additional six years at agreed-upon prices. The
Company believes the amended PPA will help relieve the financial pressure caused
by the closure of Maine Yankee as well as the need for substantial increases
in its retail rates, and is, therefore, in the best interests of the Company,
its customers and shareholders.
On December 22, 1997, the MPUC approved the amended purchase power agreement
and determined that the up-front costs created by the amended PPA will be
treated as stranded cost and, therefore, recovered in rates of the transmission
and distribution company. On February 19, 1998, the Board of Directors of FAME
authorized the issuance and sale of securities under FAME's electric rate
stabilization program.
(Page 12)
As mentioned in the "Capital Resources" section of this Annual Report, on May
29, 1998, with the completion of the FAME financing, the Company made the
up-front payment of $8.7 million to W-S, thereby completing the conditions
required under the amended purchase power agreement. As previously mentioned
in the "Four-Year Stabilization Plan" section of this Annual Report, savings
from the restructured W-S Contract are used to offset Maine Yankee replacement
power costs.
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 was 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. On December 22, 1998, FERC
issued its order establishing new tariffs for the Company. Based on the FERC
order, the Company expects to refund $1.2 millon to these customers and has
reflected these refunds as liabilities.
Transmission & Distribution Filing
On October 14, 1998, and subsequently amended on February 9, 1999, the Company
filed its determination of stranded costs, transmission and distribution costs
and rate design with the MPUC. The Company's testimony supports its $99.3
million estimate of stranded costs when deregulation occurs on March 1, 2000.
The major components include the remaining investment in Seabrook, the
above-market costs of the amended power purchase agreement and recovery of fuel
expense deferrals related to Wheelabrator-Sherman, the obligation for remaining
operating expenses and recovery of the Company's remaining investment in Maine
Yankee, and the recovery of several other regulatory assets. These stranded
costs revenue requirements will be reduced by an estimated $19.9 million should
the sale of the Company's generating assets be approved by the MPUC. The
Company's proposed annual revenue requirements supported in the filings would
be approximately $32.2 million: $19.8 million for transmission and distribution
and $12.4 million for stranded investment. Decisions by the MPUC regarding
stranded costs and the generating asset sale approval are not expected until
mid-1999. The Company cannot predict the MPUC's ultimate decision in these
matters.
Marketing Affiliate
The Company's marketing subsidiary, Energy Atlantic, LLC (EA), initially will
be involved in retail and wholesale energy transactions in Maine. Formed in
1998, EA formally began operations in January, 1999. As a start-up unregulated
Company, EA is limited in the amount of capital, based upon restrictions imposed
not only by the MPUC, but also by the Board of Directors. The Board, as well
as the MPUC, has limited the capital contributions to a maximum of $2 million,
subject to the Company's ability to meet financial covenants under its debt
instruments. EA has had success in reacquiring our largest wholesale customer,
Houlton Water Company, as of February 3, 1999; however, it is expected to
operate at a loss in 1999.
Year 2000 Issues
The Year 2000 issue is the result of computer programs being written using two
digits rather than four to define the applicable year. Computer programs that
have date-sensitive software using two digits would recognize a date using "00"
as the year 1900 rather than 2000, resulting in system failure or
miscalculations. The Company has been conducting an on-going assessment of its
computer systems, including embedded chip technology, to determine the potential
technical and economic impact which the Year 2000 issues might have on the
Company, its systems and its business operations. As a part of this process,
the Company has reviewed the computer application systems responsible for its
billing, customer information systems, and accounting transactions and has
identified modifications necessary for those systems. These modifications are
principally being made to comply with the electric industry restructuring
requirements but have incorporated changes that achieve Year 2000 compliance.
The Company has reviewed its other mission critical systems in order to identify
Year 2000 remediation or renovation measures needed for those systems and
intends to complete necessary modifications, renovations, and testing of all
mission critical systems by July 1, 1999. The compliance plans and
implementation and testing milestones are based on the Company's best estimates,
which were derived from numerous assumptions for future events, including the
continued availability of certain resources, third-party modification plans and
other known factors. In addition to the review of internal systems, the Company
is requesting assurances of Year 2000 compliance from third parties upon whom
the Company relies. The responses are being reviewed and concerns of
non-compliance are being pursued. The Company is attempting to obtain responses
and prepare contingency plans, where necessary, no later than July 1, 1999.
To date, the Company's review and testing has incurred approximately $17,000
of internal labor costs, and has not revealed material system modifications
necessary to obtain Year 2000 compliance for mission critical systems, other
than the changes necessary for electric industry restructuring discussed above.
However, $50,000 has been budgeted in 1999 for external expenditures for
unforeseen modifications to achieve Year 2000 compliance for mission critical
technology.
The assessment phase of the Year 2000 compliance project is essentially
complete and the Company is identifying risks and most reasonable likely worse
case scenarios specific to the Year 2000 non-compliance by the Company and
third-party sources. For example, for every day of a Company-wide shutdown, the
Company would lose approximately $187,000 in revenues. The Company will develop
appropriate plans for these risks no later than July 1, 1999, as mentioned
above.
Although all reasonable and available efforts will be made, the Company cannot
predict the ultimate achievement of Year 2000 compliance due to its reliance on
systems and third-parties outside the Company's control.
(Page 13)
Forward-Looking Statements
The above discussion may contain "forward-looking statements", as defined in
the Private Securities Litigation Reform Act of 1995, related to expected future
performance or our plans and objectives. Actual results could potentially
differ materially from these statements. Therefore, there can be no assurance
that actual results will not materially differ from expectations.
Factors that could cause actual results to differ materially from our
projections include, among other matters, electric utility restructuring; future
economic conditions; changes in tax rates, interest rates or rates of inflation;
and developments in our legislative, regulatory, and competitive environment.
Shareholder Information
General
The Company's Common Stock is listed and traded on the American Stock
Exchange. As of December 31, 1998 and 1997, Common Stock shares issued and
outstanding were 1,617,250. As of December 31, 1998, shares were held by 1,436
shareholders or nominees in forty-nine states, the District of Columbia, Canada,
Poland, and the United Kingdom.
The annual meeting of shareholders is held each year on the second Tuesday
in May at the Company's headquarters in Presque Isle. Market price and dividend
information relative to the two most recent calendar years are shown in the
tabulation below.
Income Tax Status of 1998 Dividends
The Company has determined that the Common Stock dividends paid in 1998 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
1998
First Quarter $14-1/4 $11-3/4 $ .25 $ .25
Second Quarter $15-1/16 $13-15/16 .25 .25
Third Quarter $15-1/8 $14-1/16 .25 .25
Fourth Quarter $17-3/16 $13-5/16 .25 .25
Total Dividends $ 1.00 $1.00
1997
First Quarter $18-3/8 $14-1/8 $ .46 $ .25
Second Quarter $14-3/4 $11-3/8 .25 .25
Third Quarter $12-7/8 $10-3/16 .25 .25
Fourth Quarter $12-13/16 $11-3/8 .25 .25
Total Dividends $ 1.21 $1.00
Dividends declared within the quarter are paid on the first day of the
succeeding quarter.
(Page 14)
Five-Year Summary of Selected Financial Data
1998 1997 1996 1995 1994
Operating Revenues
$56,626,906 $55,072,196 $57,264,165 $55,278,726 $58,368,085
Income (Loss) Before Extraordinary Items
$2,252,915 $(2,177,137) $2,110,694 $920,500 $4,845,647
Extraordinary Items, Net of Taxes
- - - (6,235,812) -
Net Income (Loss) Available for Common Stock
$2,252,915 $(2,177,137) $2,110,694 $(5,315,312) $4,845,647
Basic Earnings (Loss) Per Share of Common Stock
Income (Loss) Before Extraordinary Items
$1.39 $(1.35) $1.31 $0.57 $2.99
Extraordinary Items
- - - (3.86) -
Net Income (Loss)
$1.39 $(1.35) $1.31 $(3.29) $2.99
Dividends Per Share of Common Stock:
Declared Basis $1.00 $1.00 $1.84 $1.84 $1.84
Paid Basis $1.00 $1.21 $1.84 $1.84 $1.84
Total Assets
$164,295,548 $163,480,739 $117,192,566 $114,074,091 $122,375,442
Long-Term Debt Outstanding
$47,190,000 $39,805,000 $41,120,000 $37,435,000 $37,500,000
Less amount due within one year
1,275,000 4,155,000 1,315,000 1,315,000 65,000
Long-Term Debt
$45,915,000 $35,650,000 $39,805,000 $36,120,000 $37,435,000
(Page 15)
Report of Independent Accountants
To The Directors and Shareholders of
MAINE PUBLIC SERVICE COMPANY:
In our opinion, the accompanying consolidated balance sheets and statements
of capitalization and the related consolidated statements of operations, common
shareholders' equity and cash flows present fairly, in all material respects,
the financial position of Maine Public Service Company and its Subsidiary, Maine
and New Brunswick Electrical Power Company, Limited, as of December 31, 1998 and
1997, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which 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, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PriceWaterhouseCoopers, L.L.P.
Portland, Maine
February 12, 1999
(Page 16)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Statements of Consolidated Operations
Year Ended December 31,
1998 1997 1996
Operating Revenues $56,626,906 $55,072,196 $57,264,165
Operating Expenses
Purchased Power 29,517,841 36,608,989 30,444,691
Other Operation and
Maintenance 12,967,489 12,769,987 13,814,768
Depreciation 2,641,847 2,497,364 2,447,585
Amortization 1,607,262 1,641,819 1,649,871
Taxes Other Than Income 1,609,001 1,618,208 1,664,685
Provision (Benefit) for
Income Taxes 2,118,095 (975,093) 1,954,747
Total Operating Expenses 50,461,535 54,161,274 51,976,347
Operating Income 6,165,371 910,922 5,287,818
Other Income (Deductions)
Equity in Income of
Associated Companies 316,888 477,426 350,008
Allowance for Equity Funds
Used During Construction 36,278 18,964 7,120
Provision for Income Taxes (49,847) (61,183) (103,681)
Other - Net 111,515 59,866 95,678
Total 414,834 495,073 349,125
Income Before Interest Charges 6,580,205 1,405,995 5,636,943
Interest Charges
Long-Term Debt & Notes
Payable 4,347,258 3,592,474 3,529,867
Less Allowance for Borrowed
Funds Used During
Construction (19,968) (9,342) (3,618)
Total 4,327,290 3,583,132 3,526,249
Net Income (Loss) Available
for Common Stock $2,252,915 $(2,177,137) $2,110,694
Basic Earnings (Loss) Per
Share of Common Stock $1.39 $(1.35) $1.31
Average Shares Outstanding 1,617,250 1,617,250 1,617,250
See Notes to Consolidated Financial Statements.
(Page 17)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Statements of Consolidated Cash Flows
Year Ended December 31,
1998 1997 1996
Cash Flow From Operating Activities
Net Income (Loss) $2,252,915 $(2,177,137) $2,110,694
Adjustments to Reconcile Net Income
(Loss) to Net Cash Provided by
(Used For) Operations:
Depreciation 2,641,847 2,497,364 2,447,585
Amortization 1,643,842 1,677,399 1,649,871
Deferred Income Taxes - Net 1,698,938 812,897 (377,355)
Deferred Investment Tax Credits (70,200) (72,267) (74,662)
Allowance for Funds Used During
Construction (56,246) (28,306) (10,738)
Income on Tax-Exempt Bonds-
Restricted Funds (90,700) (159,114) (118,443)
Change in Deferred Regulatory and Debt Issuance Costs
(1,840,141) (2,304,765) (267,768)
Wheelabrator-Sherman Contract Restructuring
(8,705,750) -- --
Change in Deferred Revenues 267,921 272,716 275,846
Change in Benefit Obligations 344,121 546,080 874,267
Change in Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenue
(274,525) (800,549) 1,023,602
Deferred Fuel & Purchased Energy Cost -- (562,000) --
Other Current Assets 1,862,179 (1,266,582) (366,995)
Accounts Payable (1,200,161) 396,259 244,157
Accrued Taxes and Interest 148,897 (82,632) (161,894)
Other Current Liabilities (18,150) (19,530) (16,673)
Other - Net (752,067) (448,950) 153,205
Net Cash Flow Provided By (Used For) Operating Activities
(2,147,280) (1,719,117) 7,384,699
Cash Flow From Financing Activities
Dividend Payments (2,021,562) (1,212,938) (2,975,740)
Bond Issuance Costs (543,904) -- (398,585)
Deposit - FAME Capital Reserve Fund (2,378,386) -- --
Issuance of Long-Term Debt 11,540,000 -- 15,000,000
Drawdown of Tax-Exempt Bond Proceeds 1,934,540 1,950,692 1,063,969
Retirements of Long-Term Debt (4,155,000) (1,315,000)(11,315,000)
Short-Term Borrowings, Net 900,000 5,800,000 --
Net Cash Flow Provided By Financing Activities
5,275,688 5,222,754 1,374,644
Cash Flow Used In Investing Activities
Investment in Restricted Funds -- -- (5,000,000)
Investment in Electric Plant (3,745,302) (2,723,828) (3,444,515)
Net Cash Flow Used In Investing Activities (3,745,302) (2,723,828) (8,444,515)
Increase (Decrease) in Cash and Cash Equivalents
(616,894) 779,809 314,828
Cash and Cash Equivalents at Beginning of Year
2,070,720 1,290,911 976,083
Cash and Cash Equivalents at End of Year $1,453,826 $2,070,720 $1,290,911
Supplemental Disclosure of Cash Flow Information:
Cash Paid During The Year For:
Interest $3,763,628 $3,360,855 $3,536,812
Income Taxes (1998 and 1997 are net of tax refunds
of $2,083,783 and $851,506, respectively)
$ (1,238,467) $ (370,709) $2,939,776
See Notes to Consolidated Financial Statements.
(Page 18)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Consolidated Balance Sheets
Assets December 31,
1998 1997
Utility Plant
Electric Plant in Service $ 101,210,738 $96,395,964
Less Accumulated Depreciation 51,584,662 47,230,455
Net Electric Plant in Service 49,626,076 49,165,509
Construction Work-In-Progress 1,014,402 699,232
Total 50,640,478 49,864,741
Investments in Associated Companies 4,219,693 4,128,804
Net Utility Plant and Investments in Associated Companies
54,860,171 53,993,545
Current Assets:
Cash and Cash Equivalents 1,453,826 2,070,720
Deposits for Interest and Dividends 477,193 64,024
Accounts Receivable (less allowance for uncollectible accounts
of $215,000 in 1998 and 1997) 5,856,395 5,787,770
Unbilled Revenue 1,892,320 1,686,420
Deferred Fuel and Purchased Energy Costs 687,000 687,000
Current Deferred Income Taxes 30,508 --
Inventory 1,036,578 1,230,922
Income Tax Refund Receivable 191,516 1,965,852
Prepayments 329,834 223,333
Total 11,955,170 13,716,041
Other Assets:
Uncollected Maine Yankee Decommissioning Costs 36,037,446 43,429,478
Recoverable Seabrook Costs (less accumulated amortization and write-off
in 1998, $28,311,867; 1997, $26,888,235) 24,875,143 26,298,775
Regulatory Assets-SFAS 109 & 106 11,886,458 13,606,672
Restricted Investments (at cost, which approximates market)
2,817,254 2,262,896
Deferred Fuel and Purchased Energy Costs 9,617,677 7,135,137
Regulatory Asset - Power Purchase Agreement Restructuring
8,705,750 --
Unamortized Debt Expense (less accumulated amortization
in 1998, $973,404; in 1997, $610,597) 1,087,636 799,246
Deferred Regulatory Costs, less accumulated amortization
626,990 1,013,875
Miscellaneous 1,825,853 1,225,074
Total 97,480,207 95,771,153
Total Assets $164,295,548 $163,480,739
See Notes to Consolidated Financial Statements.
(Page 19)
Capitalization and Liabilities
December 31,
1998 1997
Capitalization (see accompanying statements):
Common Shareholders' Equity $ 34,933,027 $ 34,297,362
Long-Term Debt 45,915,000 35,650,000
Total 80,848,027 69,947,362
Current Liabilities:
Long-Term Debt Due Within One Year 1,275,000 4,155,000
Notes Payable to Banks 8,100,000 7,200,000
Accounts Payable 3,329,730 4,279,331
Accounts Payable - Associated Companies 341,210 623,821
Accrued Employee Benefits 1,000,130 968,079
Deferred Income Taxes Related to Deferred Fuel Costs -- 6,493
Dividends Declared 404,313 404,313
Customer Deposits 24,467 42,617
Taxes Accrued 57,437 77,448
Interest Accrued 971,271 802,363
Total 15,503,558 18,559,465
Deferred Credits:
Deferred Revenues 1,170,136 902,215
Uncollected Maine Yankee Decommissioning Costs 36,037,446 43,429,478
Income Taxes 25,812,477 25,722,328
Investment Tax Credits 578,006 648,206
Miscellaneous 4,345,898 4,271,685
Total 67,943,963 74,973,912
Commitments, Contingencies, and Regulatory Matters (Note 10)
Total Capitalization and Liabilities $164,295,548 $163,480,739
(Page 20)
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 1,1996 1,617,250 $13,070,750 $38,317 $31,562,104 $(5,714,376)
Net Income 2,110,694
Dividends:
Common Stock ($1.84 per share) (2,975,740)
Balance,December 31,1996 1,617,250 13,070,750 38,317 30,697,058 (5,714,376)
Net Loss (2,177,137)
Dividends:
Common Stock ($1.00 per share) (1,617,250)
Balance,December 31,1997 1,617,250 13,070,750 38,317 26,902,671 (5,714,376)
Net Income 2,252,915
Dividends:
Common Stock ($1.00 per share) (1,617,250)
Balance,December 31,1998 1,617,250 $13,070,750 $38,317 $27,538,336 $(5,714,376)
See Notes to Consolidated Financial Statements.
(Page 21)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY
Consolidated Statements of Capitalization
December 31,
1998 1997
Common Shareholders' Equity
Common Stock, $7 Par Value-Authorized 3,000,000 Shares in 1998 and 1997;
Issued 1,867,250 Shares in 1998 and 1997 $13,070,750 $13,070,750
Paid-In-Capital 38,317 38,317
Retained Earnings 27,538,336 26,902,671
Total 40,647,403 40,011,738
Treasury Stock-Total Shares of 250,000 in 1998 and 1997, at cost
(5,714,376) (5,714,376)
Total $34,933,027 $34,297,362
Long-Term Debt
First Mortgage and Collateral Trust Bonds:
7-1/8% Due Serially through 1998-Interest Payable,
May 1 and November 1 * $ -- $ 2,880,000
7.95% Due Serially through 2003-Interest Payable,
March 1 and September 1 * 1,900,000 1,925,000
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 * 3,750,000 5,000,000
Public Utility Refunding Revenue Bonds:
Series 1996: Due 2021-Variable Interest Payable Monthly (4.15% as of December
31, 1998) 15,000,000 15,000,000
Finance Authority of Maine:
1998 Taxable Electric Rate Stabilization
Revenue Notes: Due 2008 - Variable Interest Payable Monthly (5.55% as of
December 31, 1998) 11,540,000 --
Total Outstanding 47,190,000 39,805,000
Less-Amount Due Within One Year 1,275,000 4,155,000
Total $45,915,000 $35,650,000
Current Maturities and Redemption Requirements for the Succeeding Five Years Are
as Follows:
Long-Term Debt:
1999 $ 1,275,000
2000 $ 1,275,000
2001 $ 3,660,000
2002 $ 2,535,000
2003 $ 4,445,000
Thereafter $34,000,000
* Subject to early redemption premiums as defined in the bond indentures.
See Notes to Consolidated Financial Statements.
(Page 22)
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 Company's marketing subsidiary, Energy Atlantic, LLC (EA), initially will
be involved in retail and wholesale energy transactions in Maine. Formed in
1998, EA formally began operations in January, 1999. As a start-up unregulated
Company, EA is limited in the amount of capital, based upon restrictions imposed
not only by the MPUC, but also by the Board of Directors. The Board, as well
as the MPUC, has limited the capital contributions to a maximum of $2 million,
subject to the Company's ability to meet financial covenants under its debt
instruments. EA has had success in reacquiring our largest wholesale customer,
Houlton Water Company, as of February 3, 1999.
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
Certain Wheelabrator-Sherman fuel costs and the sharing provisions for
Maine Yankee replacement power costs are deferred for future recovery as defined
in the Company's rate plan. All other fuel and purchased power costs are
expensed as incurred.
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 from the temporary tariff, since the increase in the rates
charged to our transmission customers are subject to refund. On December 22,
1998, the FERC issued an order on the rates in question. The Company will be
issuing a refund of approximately $1.2 million in 1999.
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.
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%,
3.01%, and 2.99% for 1998, 1997, and 1996, 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 23)
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, the Company considers all
highly liquid securities with a maturity, when purchased, of three months or
less to be cash equivalents.
Accounting Pronouncements
During 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive Income"
and SFAS No. 131, "Disclosure about Segments of an Enterprise and Related
Information". In 1998, the FASB issued SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits" and SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities". The Company adopted SFAS
No.'s 130, 131, and 132 with no material impact to the Company's financial
position, or results of operations. Based on the Company's current business
activities, management doesn't expect the future implementation of SFAS No. 133
to have a material impact.
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 tax effect of
items not included in rate base are allocated as "Other Income (Deductions)".
1998 1997 1996
Current income taxes $ 539,204 $(1,654,540) $2,510,445
Deferred income taxes 1,698,938 812,897 (377,355)
Investment credits, net (70,200) (72,267) (74,662)
Total income taxes $ 2,167,942 $ (913,910) $2,058,428
Allocated to:
Operating income $ 2,118,095 $ (975,093) $1,954,747
Other income 49,847 61,183 103,681
Total $ 2,167,942 $ (913,910) $2,058,428
The effective income tax rates differ from the U.S. statutory rate as follows:
1998 1997 1996
Statutory rate 34.0% (34.0)% 34.0%
Excess Canadian taxes 2.7 3.3 4.2
Amortization of recoverable
Seabrook costs 6.4 9.1 6.7
State income taxes 5.9 (5.9) 5.4
Other - (2.1) (0.9)
Effective rate 49.0% (29.6)% 49.4%
The elements of deferred income tax expense (credit) are as follows:
(Dollars in Thousands) 1998 1997 1996
Temporary Differences at Statutory Rates:
Seabrook - costs $ (200) $ (200) $ (200)
Liberalized depreciation 57 80 166
AFUDC-borrowed funds (38) (38) (52)
Deferred fuel 987 1,479 559
Deferred regulatory expense (124) (266) (345)
Unbilled and deferred revenue 360 (108) (110)
Accrued pension and postretirement
benefits (112) (182) (414)
Wheelabrator-Sherman power purchase
restructuring 784 - -
Other (15) 48 19
Total temporary differences -
statutory rates $1,699 $813 $(377)
(Page 24)
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. Dividends
received from the Subsidiary were $678,426 and $736,492 in 1998 and 1996,
respectively, while no dividend was received in 1997. In 1998 the dividend
exceeded earnings from the Subsidiary by $311,335 and in 1996, earnings from the
Subsidiary exceeded the dividend by $8,608.
The following summarizes accumulated deferred income taxes established on
temporary differences under SFAS 109 as of December 31, 1998 and 1997.
(Dollars in Thousands)
1998 1997
Seabrook $13,706 $14,489
Property 8,532 9,565
Regulatory expenses 2,002 1,540
Deferred fuel 2,056 1,631
Pension and post-retirement benefits (952) (847)
Other 468 (656)
Net accumulated deferred income taxes $25,812 $25,722
3. INVESTMENTS IN ASSOCIATED COMPANIES
The Company owns 5% of the Common Stock of Maine Yankee Atomic Power
Company (Maine Yankee), a jointly-owned nuclear electric power company, and
7.49% of the Common Stock of the Maine Electric Power Company (MEPCO), a
jointly-owned electric transmission company. For additional information, see
Note 10, "Commitments, Contingencies, and Regulatory Matters - Capacity
Arrangements" regarding the closing of Maine Yankee.
Dividends received during 1998, 1997, and 1996 from Maine Yankee were
approximately $218,750, $75,000, and $333,750, respectively, and from MEPCO
approximately $7,300 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:
Maine Yankee MEPCO
(Dollars in Thousands) 1998 1997 1996 1998 1997 1996
Earnings
Operating revenues $110,608 $ 238,586 $185,661 $3,514 $25,123 $55,391
Earnings applicable to
Common Stock $ 4,916 $ 7,613 $ 6,640 $ 948 $ 1,463 $ 220
Company's equity share
of net earnings $ 246 $ 381 $ 332 $ 71 $ 110 $ 16
Investment
Total assets $1,183,298 $1,368,143 $ 602,061 $5,581 $ 4,362 $10,727
Less:
Preferred stock 16,800 17,400 18,000 -- -- --
Long-term debt 48,000 76,665 83,332 220 420 620
Other liabilities and
deferred credits 1,039,008 1,195,128 429,392 2,146 1,578 9,110
Net assets $ 79,490 $ 78,950 $ 71,337 $3,215 $ 2,364 $ 997
Company's equity in
net assets $ 3,975 $ 3,948 $ 3,567 $ 241 $ 177 $ 75
(Page 25)
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, 1998 and 1997 is
as follows:
(Dollars in Thousands)
1998 1997
Electric plant in service $ 6,987 $ 6,976
Accumulated depreciation (4,654) (4,450)
Net electric plant in service $ 2,333 $ 2,526
5. SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit arrangement with two banks. The
revolving credit agreement provides for borrowings up to $13 million until June
30, 1999, when the facility will return to $10 million. The revolving credit
agreement is subject to extension with the consent of the participating banks
and has been extended through October 1999. The $3 million increase was
effective on March 31, 1998 as part of amendments to the Company's revolving
credit agreement and line of credit agreement. These agreements contain certain
restrictive covenants including interest coverage tests and debt to equity
ratios. As of December 31, 1998, the Company was in compliance with those
covenants. The Company can utilize, at its discretion, two types of loan
options: A Loans, which are provided on a pro rata basis in accordance with
each participating bank's share of the commitment amount, and B Loans, which
are provided as arranged between the Company and each of the participating
banks. The A Loans, at the Company's option, bear interest equal to either the
agent bank's prime rate or LIBOR-based pricing. The Company also pays a
quarterly commitment fee of .50% of the unused portion of the A Loans. This fee
increased from .375% March 31, 1998 as part of the amendments discussed above.
The B Loans bear interest as arranged between the Company and the participating
bank. As of December 31, 1998, an A Loan for $6.0 million and a B Loan for $2.1
million were outstanding under this arrangement at 7.0625% and 6.75%,
respectively. As of December 31, 1997, A Loans totalling $7.2 million were
outstanding under this arrangement at 6.5%.
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 1998.
6. 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 $27,538,336 at December 31, 1998.
7. 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 1998,
1997, and 1996 plan years, the Company has made contributions of $330,000 in
1999, $305,000 in 1998, and $282,000 in 1997, respectively.
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 13.2% in 1998. 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.
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. For purposes of
determining the accrued postretirement benefit cost as of December 31, 1998, the
health care trend rate used was 10% in 1999 and graded down to 4.0% by 2009.
These rates have a significant effect on the amounts reported for the health
care plan. A one-percentage-point change in the trend rates would have the
following effects:
(Dollars in Thousands) One-Percentage-Point
Increase Decrease
Effect on total cost of service and
interest cost components $84 $(66)
Effect on postretirement benefit
obligation 836 (683)
(Page 26)
The following table sets forth the plans' net periodic benefit cost for 1998,
1997, and 1996:
(Dollars in Thousands) Pension Benefits Health Care Benefits
1998 1997 1996 1998 1997 1996
Service cost $377 $323 $298 $119 $103 $98
Interest cost 998 964 939 335 343 321
Expected return on plan assets (1,044) (981) (953) - - -
Amortization of transition (77) (77) (78) 213 213 213
Amortization of prior service cost 76 76 76 - - -
Recognized net actuarial (gain)/loss - - - - (2) -
Net periodic benefit cost $330 $305 $282 $667 $657 $632
The following table sets forth the plans' change in benefit obligation,
change in plan assets, funded status and assumptions as of December 31, 1998 and
1997:
Pension Health Care
(Dollars in Thousands) Benefits Benefits
1998 1997 1998 1997
Changes in benefit obligation
Benefit obligation at
beginning of year $14,685 $13,042 $4,933 $4,470
Service cost 377 323 119 103
Interest cost 998 964 335 343
Actuarial loss 585 1,227 848 419
Benefits paid (899) (871) (244) (402)
Benefit obligation at
end of year 15,746 14,685 5,991 4,933
Change in plan assets
Fair value of plan assets at
beginning of year 15,123 13,067 - -
Actual return on plan assets 2,354 2,645 - -
Employer contribution 305 282 244 402
Benefits paid (899) (871) (244) (402)
Fair value of plan assets
at end of year 16,883 15,123 - -
Funded Status 1,137 438 (5,991) (4,933)
Unrecognized transition
(asset) obligation (326) (403) 2,967 3,181
Unrecognized prior service cost 741 817 - -
Unrecognized net actuarial
(gain)/loss (3,170) (2,445) 508 (341)
Accrued benefit cost $(1,618) $(1,593) $(2,516) $(2,093)
Weighted-average assumptions as
of December 31 (measurement date)
Discount rate 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets 8.50% 8.50% N/A N/A
Rate of compensation increase 4.50% 4.50% N/A N/A
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 $56,000, $55,000, and $54,000 in 1998, 1997, and 1996,
respectively.
8. LONG-TERM DEBT
On May 29, 1998, FAME issued $11,540,000 of its Taxable Electric Rate
Stabilization Revenue Notes, Series 1998A (Maine Public Service Company) (the
"Notes") on behalf of the Company. The Notes were issued pursuant to, and are
secured under, a Trust Indenture by and between FAME and Peoples Heritage Bank,
Portland, Maine, as Trustee (the Trustee), for the purpose of: (i) financing
the buy down payment to Wheelabrator-Sherman of approximately $8.7 million, as
required under an amended purchase power agreement; (ii) for the Capital Reserve
Fund, as required by FAME under their Electric Rate Stabilization Program; and
(iii) for issuance costs. The Notes are limited obligations of FAME, payable
solely out of the trust estate available under the Indenture, principally the
Loan Note and Loan Agreement with the Company and the Capital Reserve Fund held
by the Trustee. The Company has issued $4 million of its first mortgage bonds
and $7.54 million of its second mortgage bonds as collateral for its performance
under the Loan Note issue pursuant to the Loan Agreement. The Notes will bear
interest at a Floating Interest Rate, initially at 5.7% per annum, and will be
adjusted weekly. On June 1, 1998, the Company purchased an interest rate cap
of 7% at a cost of $172,000, to expire June, 2008, to limit its interest rate
exposure to quarterly U.S. LIBOR rates. At the end of 1998, the cumulative
effective interest rate, including issuance costs and credit enhancement fees,
since issuance for this series was 6.58%.
On June 19, 1996, the Maine Public Utilities Financing Bank (MPUFB) issued
$15 million of its tax-exempt bonds due April 1, 2021 (the 1996 Series) on
behalf of the Company. The proceeds of the new 1996 Series were used to refund
a note from Fleet Bank of Maine, which was used to redeem the 1991 Series and
provided $5 million for the acquisition of qualifying property, of which
$419,000 remains in trust as of December 31, 1998. 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
(Page 27)
reimbursement agreement, the Company issued a second mortgage bond to the Bank
of New York, as Agent, under the reimbursement agreement, in the amount of
$15,875,000. The Company has the option of selecting weekly, monthly, annual
or term interest rate periods for the 1996 Series, and has, since issuance,
selected the weekly interest period. After considering issuance costs and
credit enhancement fees, the effective interest rate since issuance as of
December 31, 1998 has been 5.85%.
Certain long-term debt is subject to restrictive covenants consistent with
those discussed in Note 5.
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, 1998, the Company's long-term debt had a carrying
value of approximately $47.2 million and a fair value of approximately $50.5
million.
10. COMMITMENTS, CONTINGENCIES, AND REGULATORY MATTERS
Four-Year Rate Plan Approved
On November 13, 1995, the Maine Public Utilities Commission (MPUC) approved
a stipulation signed by the Company, the Commission Staff, and the Office of the
Public Advocate (OPA). 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 rate plan, as amended in January, 1998, which
applies cost of service principles, the Company's retail rates were increased
by 4.4%, 2.9%, and 3.9% on January 1, 1996, February 1, 1997 and February 1,
1998, respectively. 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 rate plan also provides for adjustments resulting from the operation
of a profit-sharing mechanism, as well as provisions for mandated costs and
plant outage provisions, particularly the shutdown of Maine Yankee, as further
explained in the "Maine Yankee" section of this Annual Report.
The Company was also permitted to defer $1,500,000 annually of the costs of
its purchases from Wheelabrator-Sherman during each of the four years of the
rate plan. The plan permits the Company to recover this deferred amount, up to
a total of $6,000,000, in rates beginning in the year 2001. The rate plan
provides for the deferral until the year 2000, of approximately $1.3 million,
net of income taxes, of uncollected retail fuel at the beginning of the rate
plan, while an additional $300,000, net of income taxes, will be collected in
rates over the rate plan period.
On January 26, 1998, the MPUC approved a 3.9% February 1, 1998 rate increase,
according to terms of a stipulation agreed to by the Company and the OPA, with
the support of the MPUC staff. The principal elements of the agreement are as
follows:
1. The rate increase effective February 1, 1998 was 3.9% consisting of the
specified increase of 2.75% and approximately $562,000 of the 1997
recoverable Maine Yankee replacement power costs (1.15%);
2. The minimum rate increase effective February 1, 1999, consisting of a
specified increase of 2.0% and the remaining recoverable 1997 Maine Yankee
replacement power costs of $523,000;
3. Maine Yankee replacement power costs for the period October 1, 1997
through September 30, 1998 will be offset by the 1998 savings under the
restructured Wheelabrator-Sherman contract (see "Capacity Arrangements"
below) with the recovery of any incremental Maine Yankee replacement power
costs subject to a final order by the MPUC in its review of the prudency
of closing Maine Yankee.
If the MPUC approved the sale of generating assets in the first quarter of
1999, the Company would agree to not increase customer rates in 1999, originally
scheduled for February 1, 1999, in accordance with the rate plan stipulation.
Instead, the Company has requested that a portion of the gain on the sale be
used to achieve its revenue requirement.
Industry Restructuring
On May 29, 1997, legislation titled "An Act to Restructure the State's
Electric Industry" was signed into law by the Governor of Maine. The principal
provisions with accounting impact on the Company are as follows:
1. Beginning on March 1, 2000, all consumers of electricity have the right
to purchase generation services directly from competitive electricity
suppliers who will not be subject to rate regulation.
2. By March 1, 2000, the Company, Central Maine Power Company (CMP), and
Bangor Hydro-Electric Company (BHE) must divest themselves of all
generation related assets and business functions except for:
a) contracts with qualifying facilities, such as the Company's power
contract with Wheelabrator-Sherman (W-S), and conservation providers;
b) nuclear assets, namely, the Company's investment in the Maine Yankee
Atomic Power Company;
c) facilities located outside the United States, i.e., the Company's
hydro facility in New Brunswick, Canada; and
d) assets that the MPUC determines necessary for the operation of the
transmission and distribution services. The MPUC can grant an
extension of the divestiture deadline if the extension will improve
the selling price. For assets not divested, the utilities are
required to sell the rights to the energy and capacity from these
assets. For more information about the Company's pending sale of its
generating assets, see "Capacity Arrangements" below.
3. The Company will continue to provide transmission and distribution
services which will be subject to continued rate regulation by the MPUC.
(Page 28)
4. Maine electric utilities will be permitted a reasonable opportunity to
recover legitimate, verifiable and unmitigable costs that are otherwise
unrecoverable as a result of retail competition in the electric utility
industry (so-called "stranded costs"). The MPUC shall determine these
stranded costs by considering:
a) the utility's regulatory assets related to generation, i.e., the
Company's unrecovered Seabrook investment;
b) the difference between net plant investment in generation assets
compared to the market value for those assets; and
c) the difference between future contract payments and the market value
of the purchased power contracts, i.e., the W-S contract.
By the end of 1999, the MPUC will have estimated the stranded costs for the
Company and the manner for the collection of these costs by the
transmission and distribution company. Customers reducing or eliminating
their consumption of electricity by switching to self-generation,
conversion to alternative fuels or utilizing demand-side management
measures cannot be assessed exit or entry fees.
The Company estimates its stranded costs to be approximately $99.3 million,
based on its February 9, 1999 filing, which included the remaining
investment in Seabrook, the estimated above-market costs of the amended
power purchase agreement and recovery of fuel expense deferrals related to
W-S, the obligation for the remaining operating expenses and recovery of
the Company's remaining investment in Maine Yankee, and the recovery of
several other regulatory assets, but does not include any benefits from the
Company's sale of generating assets.
5. The MPUC shall include in the rates to be charged by the transmission and
distribution utility decommissioning expenses for Maine Yankee. In 2003,
and every three years thereafter until the stranded costs are recovered,
the MPUC shall review and adjust the stranded cost recovery amounts and
related transition charges. However, the MPUC may adjust the amounts at
any point in time that they deem appropriate. Since the legislation
provides for our recovery of stranded costs by the transmission and
distribution company, the Company will continue to recognize existing
regulatory assets and plant costs as provided by Emerging Issues Task Force
97-4 "Deregulation of the Pricing of Electricity" (EITF 97-4).
6. Billing and metering services will be subject to competition beginning
March 1, 2002, but permits the MPUC to establish an earlier date, no sooner
than March 1, 2000.
7. All competitive providers of retail electricity must be licensed and
registered with the MPUC and meet certain financial standards, comply with
customer notification requirements, adhere to customer solicitation
requirements and are subject to unfair trade practice laws. Competitive
electricity providers must have at least 30% renewable resources in their
energy portfolios, including hydro-electric generation.
8. A standard offer service will be available, ensuring access for all
customers to reasonably priced electric power. Unregulated affiliates of
CMP and BHE providing retail electric power are prohibited from providing
more than 20% of the load within their respective service territories under
the standard offer service, while any unregulated affiliate of the Company
does not have a similar restriction.
9. Employees other than officers, displaced as a result of retail competition
will be entitled to certain severance benefits and retraining programs.
These costs will be recovered through charges collected by the regulated
transmission and distribution company.
The MPUC will conduct several rulemaking proceedings associated with the
new restructuring law. The Company is presently reviewing its business
operations and the opportunities that the new restructuring law presents.
In accordance with EITF 97-4 when all of the details of the restructuring plan
are determined by the MPUC rulemaking, the Company will discontinue application
of the Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting
for the Effects of Certain Types of Regulations", for the generating segment of
its business jurisdiction. As a result, the Company continues to defer certain
costs as regulatory assets in instances where recovery through future regulatory
cash flows is anticipated.
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.
Recoverable Seabrook costs at December 31, 1998 and 1997 are as follows:
(Dollars in Thousands)
1998 1997
Retail $43,136 $43,136
Accumulated Amortization (18,261) (16,837)
Retail, Net of Amortization $24,875 $26,299
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 $88.1 million for each reactor owned, with a maximum assessment of $10
million per reactor for any year. Maine Yankee is not liable for "events" or
"accidents" occurring after January 7, 1999, when exemption was received from
the Nuclear Regulatory Commission. These limits are also subject to inflation
indexing at five-year intervals as well as an additional 5% surcharge, should
total claims exceed funds available to pay such claims. Based on the Company's
5% equity ownership in Maine Yankee (see Note 3), the Company's share of any
retrospective premium would not exceed approximately $4.0 million or $.5 million
annually, without considering inflation indexing.
(Page 29)
Capacity Arrangements
The Company owns 5% of the Common Stock of Maine Yankee, which operated an
860 MW nuclear power plant (the "Plant") in Wiscasset, Maine. On August 6,
1997, the Board of Directors of Maine Yankee voted to permanently cease power
operations and to begin decommissioning the Plant. The Plant experienced a
number of operational and regulatory problems and did not operate after December
6, 1996. The decision to close the Plant permanently was based on an economic
analysis of the costs, risks and uncertainties associated with operating the
Plant compared to those associated with closing and decommissioning it. The
Plant's operating license from the Nuclear Regulatory Commission (NRC) was due
to expire on October 21, 2008.
The Maine Public Utilities Commission (MPUC) stayed an investigation of the
prudency of the shutdown decision and the operation of Maine Yankee prior to the
shutdown decision, pending the outcome of Maine Yankee's rate case before the
Federal Energy Regulatory Commission (FERC). The MPUC and the Maine Office of
the Public Advocate (OPA) are actively participating in the FERC proceeding, as
well as 28 municipal and cooperative utilities in New England who received
approximately 6.2% of the output from Maine Yankee (the "Secondary Purchasers").
In support of its request for an increase in decommissioning collections,
Maine Yankee submitted with its initial FERC rate case filing a 1997
decommissioning cost study performed by TLG Services, Inc. ("TLG"). During
1998, Maine Yankee engaged in an extensive competitive bid process to engage a
Decommissioning Operations Contractor ("DOC") to perform certain major
decontamination and dismantlement activities at the Plant on a fixed-price,
turnkey basis. As a result of that process, a consortium headed by Stone &
Webster Engineering Corporation ("Stone & Webster") was selected to perform such
activities under a fixed-price contract. The contract provides for, among other
undertakings, construction of an independent spent fuel storage installation
("ISFSI") and completion of major decommissioning activities and site
restoration by the end of 2004. The DOC process resulted in fixing certain
costs that had been estimated in the earlier decommissioning cost estimate
performed by TLG.
Since the filing of the FERC rate request, Maine Yankee and the active
intervenors, including among others the MPUC Staff, the OPA, the Company and
other owners, the Secondary Purchasers, and a Maine environmental group (the
"Settling Parties"), engaged in extensive discovery and negotiations. Those
parties participated in settlement discussions that resulted in an Offer of
Settlement filed by those parties with the FERC on January 19, 1999. On
February 8, 1999, the FERC Trial Staff recommended that the presiding judge
certify the settlement to the FERC and that the FERC approve it. Upon approval
by the FERC, the settlement would constitute a full settlement of all issues
raised in the consolidated FERC proceeding, including decommissioning-cost
issues and issues pertaining to the prudence of the management, operation, and
decision to permanently cease operation of the Plant. A separately negotiated
settlement filed with the FERC on February 5, 1999 would resolve the issues
raised by the Secondary Purchasers by limiting the amounts they will pay for
decommissioning the Plant and by settling other points of contention affecting
individual Secondary Purchasers.
The Offer of Settlement provides for Maine Yankee to collect $33.6 million
in the aggregate annually, effective January 15, 1998 consisting of: (1) $26.8
million for estimated decommissioning costs, and (2) $6.8 million for
ISFSI-related costs. The original filing with FERC on November 6, 1997, called
for an aggregate annual collection rate of $36.4 million for decommissioning and
the ISFSI, based on the TLG estimate. Under the settlement the amount collected
annually could be reduced to approximately $26 million if Maine Yankee is able
to (1) use for construction of the ISFSI funds held in trust under Maine law for
spent-fuel disposal, and (2) access approximately $6.8 million being held by the
State of Maine for eventual payment to the State of Texas pursuant to a compact
for low-level nuclear waste disposal, the future of which is now in question
after rejection of the selected disposal site in west Texas by a Texas
regulatory agency. Both would require authorizing legislation in Maine, which
Maine Yankee is committed to use its best efforts to obtain.
The Offer of Settlement also provides for recovery of all unamortized
investment (including fuel) in the Plant, together with a return on equity of
6.50 percent, effective January 15, 1998, on equity balances up to certain
maximum allowed equity amounts. The Settling Parties also agreed in the
proposed settlement not to contest the effectiveness of the Amendatory
Agreements submitted to FERC as part of the original filing, subject to certain
limitations including the right to challenge any accelerated recovery of
unamortized investment under the terms of the Amendatory Agreements after a
required informational filing with the FERC by Maine Yankee.
As a separate part of the Offer of Settlement, the Company, Central Maine
Power Company, and Bangor Hydro-Electric Company (the other two Maine owners of
Maine Yankee), the MPUC Staff, and the OPA entered into a further agreement
resolving retail rate issues and other issues specific to the Maine parties,
including those that had been raised concerning the prudence of the operation
and shutdown of the Plant (the "Maine Agreement"). Under the Maine Agreement,
the Company would continue to recover its Maine Yankee costs in accordance with
its most recent Rate Stabilization Plan ("RSP") order from the MPUC without any
adjustment reflecting the outcome of the FERC proceeding. To the extent that
the Company has collected from its retail customers a return on equity in excess
of the 6.50 percent contemplated by the Offer of Settlement, no refunds would
be required, but such excess amounts would be credited to the customers to the
extent required by the RSP.
The final major provision of the Maine Agreement requires the Maine owners,
for the period from March 1, 2000 through December 1, 2004, to hold their Maine
retail ratepayers harmless from the amounts by which the replacement power costs
for Maine Yankee exceed the replacement power costs assumed in the report to the
Maine Yankee Board of Directors that served as a basis for the Plant shutdown
decision, up to a maximum cumulative amount of $41 million. The Company's share
of that maximum amount would be $4.1 million for the period. The Maine
Agreement, which was approved by the MPUC on December 22, 1998, also sets forth
the methodology for calculating such replacement power costs.
The Company believes the Offer of Settlement, including the Maine
Agreement, reasonably resolves the issues presented by the parties in the Maine
Yankee FERC proceeding. If the Offer of Settlement is approved by the FERC,
several significant uncertainties regarding the recovery of Maine Yankee-related
costs are eliminated. Although all of the active parties to the proceeding have
agreed to support or, with respect to certain individual provisions, not oppose,
the Offer of Settlement, the Company cannot predict with certainty whether or
in what form the Offer of Settlement will be approved by the FERC.
(Page 30)
With the closing of Maine Yankee, a provision of the Company's rate plan
allowing the deferral of 50% of the Maine Yankee replacement power costs went
into effect on June 6, 1997. For 1998, Maine Yankee replacement power costs
were offset by net savings from the restructured Purchase Power Agreement with
Wheelabrator-Sherman, in accordance with the rate plan stipulation, resulting
in a deferral of $1.1 million. As of December 31, 1998, the Company has a
deferred Maine Yankee replacement power cost balance of approximately $3.5
million, subject to recovery in accordance with the rate plan.
The February 1, 1998, rate increase included $562,000 of the recoverable
1997 Maine Yankee replacement power costs with the remaining costs to be
included in the rate plan increase in 1999.
On September 1, 1997, Maine Yankee estimated the sum of the future payments
for the closing, decommissioning and recovery of the remaining investment in
Maine Yankee to be approximately $930 million, of which the Company's 5% share
would be approximately $46.5 million. In December, 1998, Maine Yankee updated
its estimate of decommissioning costs based on the Settlement, as discussed
above. Legislation enacted in Maine in 1997 calls for restructuring the
electric utility industry and provides for recovery of decommissioning costs,
to the extent allowed by federal regulation, through the rates charged by the
transmission and distribution companies. Based on the Maine legislation and
regulatory precedent established by the FERC in its opinion relating to the
decommissioning of the Yankee Atomic nuclear plant, the Company believes that
it is entitled to recover substantially all of its share of such costs from its
customers and, as of December 31, 1998, is carrying on its consolidated balance
sheet a regulatory asset and a corresponding liability in the amount of $36.0
million, which is the September, 1997 cost estimate of $46.5 million discussed
above reduced by the Company's post-September 1, 1997 cost-of-service payments
to Maine Yankee and reflects the cost adjustments agreed to in the Settlement.
On July 7, 1998, the Company and WPS Power Development, Inc. (WPS-PDI)
signed a purchase and sale agreement for the Company's electric generating
assets. WPS-PDI agreed to purchase 91.8 megawatts of generating capacity for
$37.4 million, which is 3.2 times higher than the net book value of the assets.
This sale of assets is required by the State's electric industry restructuring
law and requires the approvals of the MPUC and the FERC. The gain from the
asset sale would reduce stranded costs revenue requirements by $19.9 million.
On August 7, 1998, the Company filed with the MPUC for approval of this
sale. The proceeding was given the Docket No. 98-584. The Public Advocate and
the Houlton Water Company (HWC) have intervened in this proceeding. The MPUC,
in its order approving the Company's divestiture plan in MPUC Docket No. 97-670,
noted a number of concerns that it would address in Docket No. 98-584.
Principal among these concerns is whether the Company's lack of any connection
to New England electrical markets, except through the Province of New Brunswick,
Canada (NB), and the transmission system owned by the Maine Electric Power
Company (the MEPCO line) presented unique issues concerning development of an
adequate competitive retail market for electricity in northern Maine and
directed the Company to address these concerns when it filed for approval in
Docket No. 98-584.
On January 29, 1999, the Company filed a Partial Stipulation in this
Docket. Under the terms of this Stipulation, the parties agreed that access to
northern Maine's electrical markets exclusively through the transmission of the
New Brunswick Power Corporation (NB Power) and the MEPCO line "is no longer a
substantial barrier to the development of an adequate retail market for
electricity in northern Maine" and that any market power issues in northern
Maine should not prevent the MPUC from approving the sale of the Company's
generation assets to WPS-PDI.
The basis for this Stipulation is a Products and Service Agreement between
NB Power, on the one hand, and the Company, HWC, Eastern Maine Electric
Cooperative, Inc. and the Van Buren Light and Power District (collectively, "the
northern Maine utilities"), on the other. This Agreement is based in large part
upon the recommendations of the Final Report of the Maine Attorney General.
Under this Agreement, NB Power agrees to supply: (i) tie-line interruption
service, on a firm or non-firm basis, to any northern Maine utility requiring
it; (ii) ancillary services to any northern Maine utility; (iii) transmission
services through NB to any northern Maine utility at a fixed rate that can be
increased only by authorization of the proper NB regulatory authority; and (iv)
bona fide offers of energy and capacity and other electric products and service
to any customer of any northern Maine utility. It is understood that northern
Maine utilities will transfer these services at cost to competitive electricity
providers.
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. This facility is included in the
generating assets being sold, as discussed above.
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 NB Power system with
the New England Power Pool. The MEPCO transmission line is also the path by
which Wyman Unit No. 4 energy is delivered northerly into the NB Power system
and then wheeled to the Parent Company through its interconnection with NB Power
at the international border.
For several years, the Company negotiated the restructuring of the terms
of its current Power Purchase Agreement (PPA) with Wheelabrator-Sherman (W-S).
The Company was ordered into the PPA by the MPUC in 1986, which required the
purchase of the entire output (up to 126,582 MWH) of a 17.6 MW biomass plant
through December 31, 2000. Under the earlier agreement, either party could
renew the agreement for an additional fifteen years at prices to be determined
by mutual agreement, or absent mutual agreement, by the MPUC. By agreement
dated October 15, 1997, the Company and W-S amended the PPA.
Under the terms of this amendment, W-S agreed to reductions in the price
of purchased power of approximately $10 million over the PPA's current term in
exchange for an up-front payment of $8.7 million. The Company and W-S also
agreed to renew the PPA for an additional six years at agreed-upon prices. In
1999 and 2000, the effective rates will be approximately 11.3c and 12.2c per
kwh, respectively. In 2001, the rate is approximately 8.0c per kwh grading up
to approximately 8.9c in 2006, the last year of the PPA. The Company believes
the amended PPA will help relieve the financial pressure caused by the closure
of Maine Yankee as well as the need for substantial increases in its retail
rates, and is, therefore, in the best interests of the Company, its customers
and shareholders.
(Page 31)
On December 22, 1997, the MPUC approved the amended purchase power
agreement and determined that the up-front costs created by the amended PPA will
be treated as stranded cost and, therefore, recovered in rates of the
transmission and distribution company. On February 19, 1998, the Board of
Directors of FAME authorized the issuance and sale of securities under FAME's
electric rate stabilization program.
On May 29, 1998, with the completion of the FAME financing, the Company
made the up-front payment of $8.7 million to W-S, thereby completing the
conditions required under the amended purchase power agreement. Savings from
the restructured W-S Contract are used to offset Maine Yankee replacement power
costs.
On December 19, 1997, the Company announced the signing of an agreement for
the purchase of power for approximately 3.4 cents per kwh until March 1, 2000
from Northeast Empire, a 38 MW biomass plant in Ashland, Maine, as a
replacement for Maine Yankee energy.
Construction Program
Expenditures on additions, replacements and equipment for the years ended
December 31, 1998, 1997, and 1996, along with 1999 estimated expenditures, are
as follows:
1999 1998 1997 1996
(Dollars in Thousands) (Unaudited Estimates)
Parent Company
Generation $ 16 $ 4 $ 92 $ 345
Transmission 1,247 803 491 322
Distribution 2,244 2,226 1,636 2,080
General 1,491 712 425 626
Total Parent 4,998 3,745 2,644 3,373
Subsidiary 13 - 80 72
Total $5,011 $3,745 $2,724 $3,445
11. QUARTERLY INFORMATION (unaudited)
Quarterly financial data for the two years ended December 31, 1998 is as
follows:
(Dollars in Thousands Except Per Share Amounts)
1998 by Quarter
1st 2nd 3rd 4th
Operating revenues $15,597 $13,244 $12,832 $14,954
Operating expenses (13,739) (12,353) (12,059) (12,311)
Operating income 1,858 891 773 2,643
Interest charges (941) (1,017) (1,092) (1,277)
Other income-net 189 148 168 (90)
Net income $ 1,106 $ 22 $ (151) $ 1,276
Earnings per common share $ 0.68 $ 0.01 $ (0.09) $ 0.79
1997 by Quarter
1st 2nd 3rd 4th
Operating revenues $15,368 $12,339 $12,385 $14,980
Operating expenses (14,847) (11,871) (12,773) (14,670)
Operating income 521 468 (388) 310
Interest charges (848) (888) (894) (953)
Other income-net 73 67 153 202
Net income $ (254) $ (353) $(1,129) $ (441)
Loss per common share $ (0.16) $ (0.22) $ (0.70) $ (0.27)
(Pages 32-33)
MAINE PUBLIC SERVICE COMPANY
and Subsidiary (Unaudited)
All share information and per share amounts reflect the stock split on March 3,
1989.
Consolidated Financial Statistics
1998 1997 1996
Capitalization Including Bank Borrowings (year-end)
Debt (including amount due within one year) 61.28% 57.82% 52.75%
Preferred Stock (including amount due within one year)
0.00% 0.00% 0.00%
Common Shareholders' Equity 38.72% 42.18% 47.25%
Times Interest Earned - *
Before Income Taxes 2.02 0.14 2.18
After Income Taxes 1.52 0.39 1.60
Times Interest and Preferred Dividends Earned - *
After Income Taxes 1.52 0.39 1.60
Embedded Cost of Long-Term Debt (year-end) 8.10% 7.96% 8.01%
Embedded Cost of Preferred Stock (year-end) 0.00% 0.00% 0.00%
Common Shares Outstanding (year-end) 1,617,250 1,617,250 1,617,250
Basic Earnings Per Share of Common Stock (average shares)
Income Before Cumulative Effect of Accounting
Change and Extraordinary Items $1.39 $(1.35) $1.31
Cumulative Effect of Accounting Change - - -
Extraordinary Items - - -
Net Income (Loss) $1.39 $(1.35) $1.31
Dividends Per Share of Common Stock
Declared Basis $1.00 $1.00 $1.84
Paid Basis $1.00 $1.21 $1.84
Common Stock Dividend Payout Ratio - ** 71.94% - 140.46%
Book Value Per Share of Common Stock (year-end) $21.60 $21.21 $23.55
Market Price Per Share of Common Stock
High $17 3/16 $18 3/8 $22 3/8
Low $11 3/4 $10 1/4 $16 7/8
Close $15 1/4 $12 $18 1/8
Price Earnings Ratio (year-end) + 10.97 - 13.84
Number of Common Shareholders (year-end) 1,436 1,436 1,619
*Consolidated income before cumulative effect of accounting change and
extraordinary items. Includes AFUDC and Deferred Return on Seabrook Investment.
Excludes all regulatory write-offs in 1995.
**1997 net loss produces a ratio which is not meaningful. Before regulatory
write-offs in 1995.
+1997 and 1995 net losses produce ratios which are not meaningful.
Consolidated Financial Statistics
1995 1994 1993
Capitalization Including Bank Borrowings (year-end)
Debt (including amount due within one year) 49.92% 44.25% 45.83%
Preferred Stock (including amount due within one year)
0.00% 0.00% 0.00%
Common Shareholders' Equity 50.08% 55.75% 54.17%
Times Interest Earned - *
Before Income Taxes 2.51 3.25 3.49
After Income Taxes 1.80 2.26 2.36
Times Interest and Preferred Dividends Earned - *
After Income Taxes 1.80 2.26 2.36
Embedded Cost of Long-Term Debt (year-end) 9.36% 9.36% 9.14%
Embedded Cost of Preferred Stock (year-end) 0.00% 0.00% 0.00%
Common Shares Outstanding (year-end) 1,617,250 1,617,250 1,660,250
Basic Earnings Per Share of Common Stock (average shares)
Income Before Cumulative Effect of Accounting
Change and Extraordinary Items $.57 $2.99 $3.19
Cumulative Effect of Accounting Change - - -
Extraordinary Items (3.86) - -
Net Income (Loss) $(3.29) $2.99 $3.19
Dividends Per Share of Common Stock
Declared Basis $1.84 $1.84 $1.78
Paid Basis $1.84 $1.84 $1.76
Common Stock Dividend Payout Ratio - ** 98.40% 61.54% 55.80%
Book Value Per Share of Common Stock (year-end) $24.09 $29.22 $28.02
Market Price Per Share of Common Stock
High $23 7/8 $27 3/8 $31 1/4
Low $19 7/8 $20 1/2 $25 5/8
Close $21 3/8 $20 3/4 $25 7/8
Price Earnings Ratio (year-end) + - 6.94 8.11
Number of Common Shareholders (year-end) 1,634 1,650 1,720
*Consolidated income before cumulative effect of accounting change and
extraordinary items. Includes AFUDC and Deferred Return on Seabrook Investment.
Excludes all regulatory write-offs in 1995.
**1997 net loss produces a ratio which is not meaningful. Before regulatory
write-offs in 1995.
+1997 and 1995 net losses produce ratios which are not meaningful.
Consolidated Financial Statistics
1992 1991 1990
Capitalization Including Bank Borrowings (year-end)
Debt (including amount due within one year) 50.16% 53.01% 49.40%
Preferred Stock (including amount due within one year)
0.00% 0.00% 0.00%
Common Shareholders' Equity 49.84% 46.99% 50.60%
Times Interest Earned - *
Before Income Taxes 3.01 2.81 3.24
After Income Taxes 2.09 2.00 2.22
Times Interest and Preferred Dividends Earned - *
After Income Taxes 2.09 2.00 2.18
Embedded Cost of Long-Term Debt (year-end) 9.14% 9.28% 9.92%
Embedded Cost of Preferred Stock (year-end) 0.00% 0.00% 0.00%
Common Shares Outstanding (year-end) 1,660,250 1,660,250 1,761,050
Basic Earnings Per Share of Common Stock (average shares)
Income Before Cumulative Effect of Accounting
Change and Extraordinary Items $2.93 $2.62 $2.58
Cumulative Effect of Accounting Change - - -
Extraordinary Items - - -
Net Income (Loss) $2.93 $2.62 $2.58
Dividends Per Share of Common Stock
Declared Basis $1.76 $1.68 $1.68
Paid Basis $1.74 $1.68 $1.66
Common Stock Dividend Payout Ratio - ** 60.07% 64.12% 65.12%
Book Value Per Share of Common Stock (year-end) $26.61 $25.44 $24.38
Market Price Per Share of Common Stock
High $26 7/8 $26 3/8 $23 3/8
Low $24 1/4 $20 3/4 $19 1/2
Close $25 7/8 $26 3/8 $22 1/4
Price Earnings Ratio (year-end) + 8.83 10.07 8.62
Number of Common Shareholders (year-end) 1,768 1,823 2,061
*Consolidated income before cumulative effect of accounting change and
extraordinary items. Includes AFUDC and Deferred Return on Seabrook Investment.
Excludes all regulatory write-offs in 1995.
**1997 net loss produces a ratio which is not meaningful. Before regulatory
write-offs in 1995.
+1997 and 1995 net losses produce ratios which are not meaningful.
Consolidated Financial Statistics
1989 1988
Capitalization Including Bank Borrowings (year-end)
Debt (including amount due within one year) 43.12% 47.76%
Preferred Stock (including amount due within one year) 4.02% 4.41%
Common Shareholders' Equity 52.86% 47.83%
Times Interest Earned - *
Before Income Taxes 3.21 3.07
After Income Taxes 2.26 2.29
Times Interest and Preferred Dividends Earned - *
After Income Taxes 2.09 2.05
Embedded Cost of Long-Term Debt (year-end) 9.71% 10.80%
Embedded Cost of Preferred Stock (year-end) 9.74% 9.74%
Common Shares Outstanding (year-end) 1,849,550 1,865,666
Basic Earnings Per Share of Common Stock (average shares)
Income Before Cumulative Effect of Accounting
Change and Extraordinary Items $2.71 $3.12
Cumulative Effect of Accounting Change - -
Extraordinary Items - -
Net Income (Loss) $2.71 $3.12
Dividends Per Share of Common Stock
Declared Basis $1.575 $1.175
Paid Basis $1.55 $1.025
Common Stock Dividend Payout Ratio - ** 58.12% 37.66%
Book Value Per Share of Common Stock (year-end) $23.39 $22.26
Market Price Per Share of Common Stock
High $24 7/8 $20 13/16
Low $20 5/16 $11 7/8
Close $22 3/8 $20 1/2
Price Earnings Ratio (year-end) + 8.26 6.57
Number of Common Shareholders (year-end) 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 regulatory write-offs in 1995.
**1997 net loss produces a ratio which is not meaningful. Before regulatory
Write-offs in 1995.
+1997 and 1995 net losses produce ratios which are not meaningful.
1998 Sources of Income
Millions of Dollars (Total $57.1)
and Percent of Total
Residential
$20.6 Million [36.1%]
Commercial
$18.4 Million [32.2%]
Industrial
$10.2 Million [17.9%]
Other Electric Sales
$5.6 Million [9.8%]
Other Income
$2.3 Million [4.0%]
1998 Distribution of Income
Millions of Dollars (Total $57.1)
and Percent of Total
Fuel & Purchased Power
$30.4 Million [53.3%]
Other Operating Expenses
$9.5 Million [16.6%]
Wages and Employee Benefits
$6.8 Million [11.9%]
Interest
$4.3 Million [7.5%]
Taxes
$3.7 Million [6.5%]
Common Dividends
$1.6 Million [2.8%]
Retained Earnings
$0.8 Million [1.4%]
YEAR-END CAPITALIZATION
(Percent)
Total Debt Common Equity
1994 44.25 55.75
1995 49.92 50.08
1996 52.75 47.25
1997 57.82 42.18
1998 61.28 38.72
(Pages 34 -35)
MAINE PUBLIC SERVICE COMPANY
and Subsidiary (Unaudited)
Consolidated Operating Statistics
1998 1997 1996
Operating Revenues
Residential $20,592,662 $20,391,688 $19,961,192
Commercial and Industrial - Small 18,363,186 17,418,761 16,420,167
Commercial and Industrial - Large 10,249,381 9,452,158 10,111,758
Municipal Street Lighting 585,053 546,071 538,890
Area Lighting 276,029 268,208 273,985
Other Municipal and Other
Public Authorities 478,694 653,563 710,106
Other Electric Utilities 4,229,874 4,307,528 6,893,598
Other Operating Revenues 1,852,027 2,034,219 2,354,469
Total Operating Revenues $56,626,906 $55,072,196 $57,264,165
Number of Customers (average)
Residential 28,635 28,561 28,515
Commercial and Industrial Small 5,630 5,586 5,541
Commercial and Industrial - Large 16 15 15
Municipal Street Lighting 39 39 38
Area Lighting 1,049 1,063 1,059
Other Municipal and Other
Public Authorities 4 5 5
Other Electric Utilities 8 11 10
Total Customers 35,381 35,280 35,183
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 35,764 26,758 10,201
Hydro 123,288 107,734 168,993
Diesel (800) (429) (674)
Purchases:
Nuclear Generated - - 249,083
Fossil Fuel Generated 501,007 496,888 372,431
Inadvertent Received (Delivered) (4,049) (494) 741
Total 655,210 630,457 800,775
Losses, Unaccounted for and Unbilled 39,903 34,128 33,303
Company Use 1,414 1,695 1,517
Electricity Sold 613,893 594,634 765,955
Sales:
Residential 163,073 167,368 169,298
Commercial and Industrial-Small 173,168 168,976 163,804
Commercial and Industrial-Large 144,228 134,741 134,588
Municipal Street Lighting 1,762 1,676 1,658
Area Lighting 1,416 1,443 1,418
Other Municipal and Other Public Authorities 6,827 10,204 10,090
Other Electric Utilities 123,419 110,226 285,099
Total Sales 613,893 594,634 765,955
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 5,695 5,860 5,937
Revenue $ 719.14 $ 713.97 $ 700.02
Revenue per Kilowatt-hour 12.63c 12.18c 11.79c
(Pages 34 -35)
MAINE PUBLIC SERVICE COMPANY
and Subsidiary (Unaudited)
Consolidated Operating Statistics
1995 1994 1993
Operating Revenues
Residential $19,080,662 $19,646,681 $19,669,749
Commercial and Industrial - Small 15,723,439 15,614,453 15,177,992
Commercial and Industrial - Large 9,437,409 9,225,131 9,554,566
Municipal Street Lighting 524,616 517,793 512,439
Area Lighting 272,896 271,115 269,925
Other Municipal and Other
Public Authorities 903,370 2,105,933 3,597,514
Other Electric Utilities 7,573,360 8,481,483 9,188,561
Other Operating Revenues 1,762,974 2,505,496 2,505,466
Total Operating Revenues $55,278,726 $58,368,085 $60,476,212
Number of Customers (average)
Residential 28,385 28,300 28,220
Commercial and Industrial - Small 5,465 5,418 5,364
Commercial and Industrial - Large 15 16 16
Municipal Street Lighting 38 38 38
Area Lighting 1,048 1,048 1,061
Other Municipal and Other
Public Authorities 5 8 8
Other Electric Utilities 9 9 8
Total Customers 34,965 34,837 34,715
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 22,867 18,559 26,456
Hydro 121,252 118,759 148,719
Diesel 1,046 (153) 169
Purchases:
Nuclear Generated 9,718 326,334 282,199
Fossil Fuel Generated 508,266 290,172 288,487
Inadvertent Received (Delivered) (1,449) 651 (1,053)
Total 661,700 754,322 744,977
Losses, Unaccounted for and Unbilled 36,411 42,880 43,944
Company Use 1,490 1,518 1,542
Electricity Sold 623,799 709,924 699,491
Sales:
Residential 168,640 175,685 176,732
Commercial and Industrial-Small 165,914 167,485 162,949
Commercial and Industrial-Large 128,478 127,327 135,029
Municipal Street Lighting 1,655 1,642 1,630
Area Lighting 1,457 1,472 1,482
Other Municipal & Other Public Authorities 11,747 28,621 53,021
Other Electric Utilities 145,908 207,692 168,648
Total Sales 623,799 709,924 699,491
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 5,941 6,208 6,263
Revenue $ 672.21 $ 694.23 $ 697.01
Revenue per Kilowatt-hour 11.31c 11.18c 11.13c
(Pages 34 -35)
MAINE PUBLIC SERVICE COMPANY
and Subsidiary (Unaudited)
Consolidated Operating Statistics
1992 1991 1990
Operating Revenues
Residential $18,704,900 $19,194,469 $18,189,325
Commercial and Industrial - Small 13,787,720 13,991,693 12,708,677
Commercial and Industrial - Large 8,891,123 10,105,693 10,115,772
Municipal Street Lighting 499,814 512,640 505,063
Area Lighting 261,984 267,518 262,845
Other Municipal and Other
Public Authorities 3,761,815 3,977,098 3,611,220
Other Electric Utilities 8,150,094 7,328,914 9,649,398
Other Operating Revenues 2,626,190 2,460,062 1,701,167
Total Operating Revenues $56,683,640 $57,838,087 $56,743,467
Number of Customers (average)
Residential 28,102 28,052 27,983
Commercial and Industrial - Small 5,261 5,205 5,108
Commercial and Industrial - Large 15 15 15
Municipal Street Lighting 38 38 38
Area Lighting 1,075 1,091 1,114
Other Municipal and Other
Public Authorities 8 8 8
Other Electric Utilities 7 7 7
Total Customers 34,506 34,416 34,273
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 33,509 28,868 59,252
Hydro 130,407 135,619 176,832
Diesel (636) (178) (186)
Purchases:
Nuclear Generated 263,313 307,769 253,321
Fossil Fuel Generated 300,930 246,172 289,177
Inadvertent Received (Delivered) (2,232) 1,861 (151)
Total 725,291 720,111 778,245
Losses, Unaccounted for and Unbilled 43,686 42,114 40,613
Company Use 1,462 1,499 1,559
Electricity Sold 680,143 676,498 736,073
Sales:
Residential 176,814 176,028 178,011
Commercial and Industrial-Small 155,267 149,709 146,881
Commercial and Industrial-Large 129,981 139,931 155,782
Municipal Street Lighting 1,864 2,336 2,697
Area Lighting 1,538 1,591 1,643
Other Municipal and Other Public Authorities 58,388 57,687 57,034
Other Electric Utilities 156,291 149,216 194,025
Total Sales 680,143 676,498 736,073
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 6,292 6,275 6,361
Revenue $ 665.61 $ 684.25 $ 650.01
Revenue per Kilowatt-hour 10.58c 10.90c 10.22c
(Pages 34 -35)
MAINE PUBLIC SERVICE COMPANY
and Subsidiary (Unaudited)
Consolidated Operating Statistics
1989 1988
Operating Revenues
Residential $18,537,902 $17,787,713
Commercial and Industrial - Small 13,379,207 12,374,719
Commercial and Industrial - Large 9,785,058 9,673,266
Municipal Street Lighting 573,351 559,478
Area Lighting 288,378 285,979
Other Municipal and Other
Public Authorities 3,736,851 3,546,473
Other Electric Utilities 10,980,817 9,244,874
Other Operating Revenues (62,314) 649,746
Total Operating Revenues $57,219,250 $54,122,248
Number of Customers (average)
Residential 27,737 27,358
Commercial and Industrial - Small 4,940 4,866
Commercial and Industrial - Large 17 18
Municipal Street Lighting 38 37
Area Lighting 1,155 1,166
Other Municipal and Other
Public Authorities 8 8
Other Electric Utilities 8 7
Total Customers 33,903 33,460
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 91,361 81,583
Hydro 106,571 112,953
Diesel 2,664 1,933
Purchases:
Nuclear Generated 369,315 266,851
Fossil Fuel Generated 217,166 299,838
Inadvertent Received (Delivered) 1,611 (677)
Total 788,688 762,481
Losses, Unaccounted for and Unbilled 42,474 44,883
Company Use 1,723 1,555
Electricity Sold 744,491 716,043
Sales:
Residential 178,668 176,680
Commercial and Industrial-Small 145,364 139,220
Commercial and Industrial-Large 145,307 148,220
Municipal Street Lighting 2,722 2,695
Area Lighting 1,580 1,585
Other Municipal and Other Public Authorities 59,190 59,268
Other Electric Utilities 211,660 188,375
Total Sales 744,491 716,043
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 6,442 6,458
Revenue $ 668.35 $ 650.18
Revenue per Kilowatt-hour 10.38c 10.07c
Page 36
Board
of
Directors
Maine Public Service
Company's ten-member
Board of Directors is
composed of nine outside
directors and one inside
director, Paul R. Cariani.
Their diverse business,
educational, professional,
and civic backgrounds are
valuable assets that provide
a broad perspective to the
issues concerning the
Company.
G. Melvin Hovey
Chairman of the Board
and Retired President
Maine Public Service Company
Presque Isle, Maine
Pension Investment Committee
Budget and Finance Committee
Robert E. Anderson
Chairman of the Board,
Chief Financial Officer and
Former President
F. A. Peabody Company
Houlton, Maine
Pension Investment Committee
Budget and Finance Committee
Paul R. Cariani
President and CEO
Maine Public Service Company
Presque Isle, Maine
Nominating Committee
Donald F. Collins
Director and Retired President
S. W. Collins Co.
Caribou, Maine
Audit Committee
Nominating Committee
D. James Daigle
President
D & D Management Co.
Orlando, Florida
Executive Compensation Committee
Richard G. Daigle
President and CEO
Daigle Oil Company
Cold Brook Energy, Inc., President
Fort Kent, Maine
Audit Committee
Executive Compensation Committee
J. Gregory Freeman
President and CEO
Pepsi-Cola Bottling Company
of Aroostook, Inc.
Presque Isle, Maine
Budget and Finance Committee
Nominating Committee
Deborah L. Gallant
President and CEO
D. Gallant Management Associates
Portland, Maine
Executive Compensation Committee
Nathan L. Grass
President
Grassland Equipment, Inc.
Presque Isle, Maine
Executive Compensation Committee
J. Paul Levesque
President and CEO
J. Paul Levesque & Sons, Inc.
(Lumber Mill) and
Antonio Levesque & Sons, Inc.
(Logging Operation)
Ashland, Maine
Audit Committee
Pension Investment Committee
Executive Officers
Paul R. Cariani
President & Chief Executive Officer
Frederick C. Bustard
Vice President
Power Supply & Environment
Larry E. LaPlante
Vice President
Finance, Administration, & Treasurer
Stephen A. Johnson
Vice President
Customer Service & General Counsel
Peter C. Louridas
Assistant To The President
Michael A. Thibodeau
Assistant Vice President
Human Resources
Kurt A. Tornquist
Controller, Assistant Treasurer
& Assistant Secretary
Walter J. Elish
Director of Economic Development
Transfer Agent
The Bank of New York
Shareholder Relations Dept. - 11E
P. O. Box 11258, Church Street Station
New York, NY 10286
Tel. No. 1-800-524-4458
E-Mail: [email protected]
Stock Registrar
The Bank of New York
Annual Meeting
Tuesday, May 11, 1999
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@ mfx.net
Exhibit 4(t)
THIS INSTRUMENT GRANTS A SECURITY INTEREST
BY A TRANSMITTING UTILITY
THIS INSTRUMENT CONTAINS AFTER-ACQUIRED PROPERTY PROVISIONS
MAINE PUBLIC SERVICE COMPANY
TO
FIRST TRUST
NATIONAL ASSOCIATION
Trustee
SEVENTEENTH SUPPLEMENTAL INDENTURE
Dated as of April 1, 1997
Supplementing and Modifying Indenture of Mortgage and
Deed of Trust dated as of October 1, 1945
and
Relating to an Issue of Mortgage and
Collateral Trust Bonds, Series due 2005
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 SEVENTEENTH SUPPLEMENTAL INDENTURE (hereinafter called
the "Seventeenth Supplemental Indenture"), dated as of April 1,
1997, made by MAINE PUBLIC SERVICE COMPANY, a Maine corporation
(hereinafter called the "Company"), party of the first part, and
FIRST TRUST NATIONAL ASSOCIATION (as successor to CONTINENTAL BANK,
NATIONAL ASSOCIATION (formerly, Continental Illinois National Bank
and Trust Company of Chicago)), a national banking association duly
organized and existing under the laws of the United States of
America, and having its principal place of business in the City of
Chicago, State of Illinois (hereinafter called the "Trustee"),
party of the second part.
WHEREAS, the Company has heretofore executed and delivered to
the Trustee an Indenture of Mortgage and Deed of Trust, dated as of
October 1, 1945 (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 "First 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 an initial series of Bonds designated
as "First Mortgage and Collateral Trust Bonds, 2 7/8% Series due
1975" (herein sometimes called "Bonds of the 1975 Series"); and
WHEREAS, the Company has heretofore executed and delivered to
the Trustee a First Supplemental Indenture, dated as of September
1, 1950, pursuant to which the Company provided for the creation of
a second series of Bonds designated as "First Mortgage and
Collateral Trust Bonds, 3% Series due 1980" (herein sometimes
called "Bonds of the 1980 Series"), a Second Supplemental
Indenture, dated as of February 1, 1955, pursuant to which the
Company provided for the creation of a third series of Bonds
designated as "First Mortgage and Collateral Trust Bonds, 3.35%
Series due 1985" (herein sometimes called "Bonds of the 1985
Series"), a Third Supplemental Indenture, dated as of September 1,
1960, pursuant to which the Company provided for the creation of a
fourth series of Bonds designated as "First Mortgage and Collateral
Trust Bonds, 5 1/2% Series due 1990" (herein sometimes called
"Bonds of the 1990 Series"), a Fourth Supplemental Indenture, dated
as of January 1, 1965, pursuant to which the Company provided for
the creation of a fifth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 4 3/4% Series due 1995" (herein sometimes
called "Bonds of the 1995 Series"), a Fifth Supplemental Indenture, dated as of
May 1, 1968, pursuant to which the Company provided for the creation of a sixth
series of Bonds designated as "First Mortgage and Collateral Trust Bonds, 7 1/8%
Series due 1998" (herein sometimes called "Bonds of the 1998 Series"), a Sixth
Supplemental Indenture, dated as of March 1, 1973, pursuant to which the Company
supplemented and modified the Original Indenture and provided for the creation
of a seventh series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, 7.95% Series due 2003" (herein sometimes called "Bonds of the 2003
Series"), a Seventh Supplemental Indenture, dated as of September 1, 1975,
pursuant to which the Company supplemented and modified the Original Indenture
and provided for the creation of an eighth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 10 5/8% Series due 1995" (herein sometimes
called "Bonds of the Second 1995 Series"), an Eighth Supplemental Indenture,
dated as of January 1, 1977, pursuant to which the Company supplemented the
Original Indenture, a Ninth Supplemental Indenture, dated as of March 1, 1978,
pursuant to which the Company supplemented and modified the Original Indenture,
a Tenth Supplemental Indenture, dated as of October 1, 1979, pursuant to which
the Company supplemented the Original Indenture and provided for the creation
of a ninth series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, 10 1/4% Series due 2004" (herein sometimes called "Bonds of the 2004
Series"), an Eleventh Supplemental Indenture, dated as of January 15, 1983,
pursuant to which the Company supplemented the Original Indenture and provided
for the creation of a tenth series of Bonds designated as "First Mortgage and
Collateral Trust Bonds, 13 7/8% Series due 1992" (herein sometimes called "Bonds
of the 1992 Series"), a Twelfth Supplemental Indenture, dated as of July 1,
1984, pursuant to which the Company supplemented the Original Indenture and
provided for the creation of an eleventh series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 16.30% Series due 1989" (herein sometimes
called "Bonds of the 1989 Series"), a Thirteenth Supplemental Indenture, dated
as of July 1, 1984, pursuant to which the Company supplemented the Original
Indenture and provided for the creation of a twelfth series of Bonds designated
as "First Mortgage and Collateral Trust Bonds, Floating Rate Series A due 1985"
(herein sometimes called "Bonds of the Series A due 1985"), a Fourteenth
Supplemental Indenture, dated as of July 1, 1985, pursuant to which the Company
supplemented the Original Indenture and provided for the creation of a
thirteenth series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, Floating Rate Series B due 1986" (herein sometimes called "Bonds of the
Series B due 1986"), a Fifteenth Supplemental Indenture, dated as of March 1,
1986, pursuant to which the Company supplemented the Original Indenture and
provided for the creation of a fourteenth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 11% Series due 1996" (herein sometimes
called "Bonds of the 1996 Series) and a Sixteenth Supplemental Indenture, dated
as of September 1, 1991, pursuant to which the Company supplemented the Original
Indenture and provided for the creation of a fifteenth series of Bonds
designated as "First Mortgage and Collateral Trust Bonds, 9.775% Series due
2011" (herein sometimes called "Bonds of the 2011 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 First Mortgage and Collateral Trust Bonds of Series and in
principal amounts as follows:
Issued Outstanding
Bonds of the 1998 Series $4,000,000 2,920,000
Bonds of the 2003 Series 2,500,000 1,925,000
Bonds of the 2011 Series 15,000,000 15,000,000
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 First Mortgage and Collateral Trust Bonds, Series due 2005 (herein
sometimes called the "Bonds of the 2005 Series"), and the Original Indenture
provides that each series of Bonds (except the Bonds of the 1975 Series) shall
be created by an indenture supplemental to the Original Indenture; and
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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 Sixteenth 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 2005 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 Seventeenth Supplemental
Indenture, a valid and binding mortgage and deed of trust 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 Seventeenth Supplemental Indenture and
the issue of the Bonds of the 2005 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 Seventeenth Supplemental Indenture (the Original Indenture, as supplemented
by the First, Second, Third, Fourth, Fifth, Eighth, Tenth, Eleventh, Twelfth,
Thirteenth, Fourteenth, Fifteenth and Sixteenth Supplemental Indentures, as
supplemented and modified by the Sixth, Seventh and Ninth Supplemental
Indentures and as supplemented and modified by this Seventeenth 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, if any, and interest on, all Bonds at any time issued and outstanding
under the Indenture,
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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 Seventeenth 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 Seventeenth Supplemental Indenture and
by these presents does grant, bargain, sell, alien, remise,
release, convey, assign, transfer, mortgage, pledge, set over and
confirm unto First Trust National Association, as Trustee under the
Indenture, and to its assigns forever, all property, real, personal
or mixed, acquired since the execution and delivery of the
Sixteenth 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:
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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
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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.
(4) A certain piece or parcel of land situated in the Westerly part of
Original Lot No. One Hundred Thirty (#130) in Township 18, Range 5, W.E.L.S.,
now Madawaska, in the County of Aroostock and State of Maine, being more
particularly bound and described as follows:
Commencing at the East corner of the parcel conveyed to Maine
Public Service Company by deed recorded in the Northern Aroostook
Registry of Deeds in Volume 330, Page 566, said point being also
the North corner of Lot No. Thirty-One (#31) on Madawaska town map
sheet number Seven (7) as prepared by J.W. Sewall Co.; thence
Northwesterly along the Northeast property line of the said Maine
Public Service Company parcel to the North corner of said MPS
parcel, a distance of One Hundred Forty-nine and Seven Tenths
(149.7) feet; thence Northeasterly on a continuation of the
Northwest property line of said MPS parcel, to the Southwest
property line of the parcel conveyed to the Inhabitants of the Town
of Madawaska by Fraser Paper, Ltd, a distance of Fifty (50) feet,
more or less, said property line being also the boundary between
the parcel owned by Eldon J. Cyr and the parcel owned by the
Inhabitants of Madawaska, thence Southeasterly along the Southwest
property line of the parcel conveyed to the Inhabitants of the Town
of Madawaska to the South corner of the parcel conveyed to the
Inhabitants of Madawaska, said corner being also the West corner of
Lot Six (6) on Madawaska town map sheet Seven (7) as prepared by J.
W. Sewall Co., a distance of One Hundred Fifty (150) feet, more or
less, thence Southwesterly, a distance of Fifty (50) feet to the
point of beginning.
Being part of the premises conveyed to Eldon J. Cyr by Warranty Deed of
Fraser Paper, Limited, dated May 6, 1994, recorded in the Northern Aroostock
Registry of Deeds in Volume 948, Page 98.
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
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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:
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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 Northern 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 Co. 3/16/94 2669 20-24 Houlton
RIGHT-OF-WAY, ROUTE 11 REBUILD, SO CALLED
A 34,500 volt transmission line in Aroostook County, Maine owned and
operated by Maine Public Service Company from junction of Rt. 163 & Rt. 11 in
Ashland, Maine and southerly along Rt. 11, a distance of approximately 2.05
miles, said Maine Public Service
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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:
Matt Walton 2/4/97 2985 322 Houlton
Mark D. Rafford, Sr. 2/4/97 2985 320 Houlton
Laura & Bernard Howes, Jr. 2/4/97 2985 317 Houlton
Kevin & Barbara Robinson 2/4/97 2985 315 Houlton
Melvin P. Graham 2/4/97 2985 313 Houlton
Milton & Dawn Clark 2/4/97 2985 311 Houlton
Chester B. & Katherine
B. Rafford 2/4/97 2985 309 Houlton
Sherman L. & Charlotte
O. Weaver 2/4/97 2985 297 Houlton
Beatrice Weaver 2/4/97 2985 299 Houlton
Dwight & Candace D. Junkins 2/4/97 2985 301 Houlton
John Beaulier 2/4/97 2985 303 Houlton
Clifford G. & Thelma A. White 2/4/97 2985 305 Houlton
Julie Belanger & Althea
Holmes 2/4/97 2985 307 Houlton
Glori Coty & Barry Baranowski 2/4/97 2985 291 Houlton
Artimas & Rosemary M. Coffin 2/4/97 2985 295 Houlton
Robert & Bonnie Bowring 2/4/97 2985 293 Houlton
RIGHT-OF-WAY, FORT KENT WASTE WATER TREATMENT PLANT, SO CALLED
A 34,500 volt transmission line in Aroostock County, Maine
owned and operated by Maine Public Service Company from Route 161
in Ashland, Maine south .28 miles to the Fort Kent Waste Water
Treatment Plant, said Maine Public Service Company line being
constructed for the most part on a right-of-way conveyed to Maine
Public Service Company by the following deed:
Recorded
Grantor Date Vol. Page Registry at:
Fort Kent Utility District 10/17/96 1048 276 Fort Kent
The foregoing rights-of-way are conveyed subject to
reservations, conditions, restrictions, limitations and exceptions
referred to or mentioned in the deeds above listed.
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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,
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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 VII 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
VII; and
(b) All property which prior to the execution and
delivery of this Seventeenth 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.
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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, as modified by the provisions of the Sixth Supplemental Indenture,
the Seventh Supplemental Indenture and the Ninth Supplemental 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 2005 Series and Certain
Provisions Relating Thereto
Section 2.01. Terms of the Bonds of the 2005 Series. There shall be a
series of Bonds, known as and entitled "First Mortgage and Collateral Trust
Bonds, Series due 2005" (herein
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referred to as the "Bonds of the 2005 Series"), and the form thereof shall be
substantially as hereinafter set forth in Section 2.02.
The Bonds of the 2005 Series are issued to secure the obligations of the
Company under the Revolving Credit Agreement, dated as of October 8, 1987, by
and among the Company, the signatory Banks thereto and The Bank of New York, as
agent (in such capacity, "BNY Agent"), as amended by Amendment No. 1, dated as
of October 8, 1989, Amendment No. 2, dated as of May 11, 1992, Amendment No. 3,
dated as of October 8, 1995, and Amendment No. 4, dated as of March 28, 1997,
together with any amendments, modifications or supplements thereto, extensions,
renewals, deferrals, refunding or refinancing thereof or replacements or
successors therefor which may hereafter exist (the "Revolving Credit
Agreement"), pursuant to which the signatory Banks thereto have each, severally,
agreed, subject to the terms and conditions thereof, to make Loans (as defined
therein) evidenced by a series of promissory notes, collectively the Notes (as
defined therein), with the obligations and liabilities (including, but not
limited to, obligations with respect to any fees, disbursements, or other
expenses and indemnification) of the Company due and to become due under the
Notes or otherwise in respect of the Revolving Credit Agreement, in each case,
whether direct or indirect, joint or several, absolute or contingent, liquidated
or unliquidated, now or hereafter existing, extended, renewed, deferred,
refunded, refinanced or restructured, and whether or not from time to time
decreased or extinguished and later increased, created or incurred, and
including all indebtedness of the Company under any instrument now or hereafter
evidencing any of the foregoing, all being hereinafter called the "Revolving
Credit Obligations".
The aggregate principal amount of the Bonds of the 2005 Series which may
be authenticated and delivered and outstanding under this Seventeenth
Supplemental Indenture shall be limited to $11,000,000 except for duplicate
Bonds, authenticated and delivered pursuant to Section 2.12 of the Original
Indenture. The definitive Bonds of the 2005 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
2005 Series shall be the date of commencement of the first interest period for
such Bonds. All Bonds of the 2005 Series shall mature April 1, 2005, and shall
bear interest at the applicable rate of interest as set forth in, and in
accordance with, the Revolving Credit Agreement until the payment of the
principal thereof. Both principal of and interest on the Bonds of the 2005
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 Chicago, Illinois, of the
Trustee or, at the office of its successor as Trustee, except that, in case of
the redemption as a whole at any time of Bonds of the 2005 Series then
outstanding, the Company may designate in the redemption notice other offices
or agencies at which, at the option of the registered holders, Bonds of the 2005
Series may be surrendered for redemption and payment; and in the case of
interest on Bonds of the 2005 Series, at the option of the registered holder,
at the agency of the Company in the Borough of Manhattan, City and State of New
York, in each case to the holder of record on the record date as hereinbelow
defined. Interest on the
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Bonds of the 2005 Series shall, unless otherwise directed by the respective
registered holders thereof, be paid by checks payable to the order of the
respective holders entitled thereto, and mailed by the Trustee by first class
mail, postage prepaid, to such holders at their respective registered addresses
as shown on the Bond register for the Bonds of the 2005 Series.
The definitive Bonds of the 2005 Series may be issued in the form of Bonds
engraved, printed or lithographed on steel engraved borders and the signature
of the President, or a Vice President and of the Secretary or an Assistant
Secretary of the Company may be facsimile. Bonds of the 2005 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.
Notwithstanding any provision in the Original Indenture to the contrary,
the person in whose name any Bond of the 2005 Series is registered at the close
of business on any record date (as hereinbelow defined) with respect to any
interest payment date shall be entitled to receive the interest payable on such
interest payment date notwithstanding the cancellation of such Bond of the
2005 Series upon any transfer or exchange thereof (including any exchange
effected as an incident to a partial redemption thereof) subsequent to the
record date and prior to such interest payment date, except that, if and to the
extent that the Company shall default in the payment of the interest due on such
interest payment date, then the registered holders of Bonds of the 2005 Series
on such record date shall have no further right to or claim in respect of such
defaulted interest as such registered holders on such record date, and the
persons entitled to receive payment of any defaulted interest thereafter payable
or paid on any Bonds of the 2005 Series shall be the registered holders of such
Bonds of the 2005 Series on the record date for payment of such defaulted
interest. The term "record date" as used in this Section 2.01, and in the form
of the Bonds of the 2005 Series, with respect to any interest payment date
applicable to the Bonds of the 2005 Series, shall mean the August 15 next
preceding a September 1 interest payment date or the February 15 next preceding
a March 1 interest payment date, as the case may be, or a special record date
established for defaulted interest as hereinafter provided.
In the case of failure by the Company to pay any interest when due, the
claim for such interest shall be deemed to have been transferred by transfer of
any Bond of the 2005 Series registered on the Bond register, and the Company by
not less than 10 days written notice to bondholders may fix a subsequent record
date, not more than 15 days prior to the date fixed for the payment of such
interest, for determination of holders entitled to payment of such interest.
Such provision for establishment of a subsequent record date, however, shall in
no way affect the rights of bondholders or of the Trustee consequent on any
default.
Except as provided in this Section 2.01, every Bond of the 2005 Series
shall be dated as provided in Section 2.05 of the Original Indenture except that
upon original issuance of the Bonds of the 2005 Series, the Bonds of the 2005
Series shall be dated the date of authentication. Notwithstanding any provision
in the Original Indenture to the contrary, so long as there is no
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existing default in the payment of interest on the Bonds of the 2005 Series, all
Bonds of the 2005 Series authenticated by the Trustee between the record date
for any interest payment date and such interest payment date shall be dated such
interest payment date and shall bear interest from such interest payment date.
As permitted by the provisions of Section 2.10 of the Original Indenture
and upon payment at the option of the Company of a sum sufficient to reimburse
it for any stamp tax or other governmental charge as provided in Section 2.11
of the Original Indenture, Bonds of the 2005 Series may be exchanged for other
Bonds of the 2005 Series of different authorized denominations of like aggregate
principal amount. Notwithstanding the provisions of Section 2.11 or the last
sentence of the first paragraph of Section 2.12 of the Original Indenture, no
further sum, other than the sum sufficient to reimburse the Company for any
stamp taxes or other governmental charges, shall be required to be paid upon any
exchange or replacement of Bonds of the 2005 Series or upon any transfer
thereof.
The Bonds of the 2005 Series shall be nontransferable prior to maturity
except upon the prior written consent of the Company or to effect transfer to
any successor of BNY Agent if BNY Agent shall have resigned as agent under the
Revolving Credit Agreement, any such transfer to be made at the principal
corporate trust office of the Trustee in the City of Chicago, Illinois, upon
surrender and cancellation of such Bonds of the 2005 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 2005 Series or by his duly
authorized attorney, and thereupon a new Bond of the 2005 Series, for a like
principal amount, will be issued to the successor 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 2005 Series. Notwithstanding any provision in the
Original Indenture to the contrary, neither the Company nor the Trustee shall
be required to make transfers or exchanges of Bonds of the 2005 Series for a
period of ten days next preceding any designation of the Bonds of the 2005
Series to be redeemed and neither the Company nor the Trustee shall be required
to make transfers or exchanges of any bonds designated in whole for redemption
or that part of any bond designated in part for redemption.
The Bonds of the 2005 Series, limited as provided in Section 2.01 hereof
to $11,000,000 in aggregate principal amount, shall be issued to BNY Agent to
secure the Revolving Credit Obligations, including, without limitation, any
future advances or protective advances made under the Revolving Credit Agreement
(with the terms "future advances" and "protective advances" having the meanings
ascribed to such terms in 33 Maine Revised Statutes Section 505.1), to the same
extent as if such future advances were made on the date hereof and with the
understanding that the Revolving Credit Obligations may decrease or increase
from time to time. The Bonds of the 2005 Series securing said Revolving Credit
Obligations (including such future advances and such protective advances) shall
have the same right, lien and privilege under the Indenture and shall be equally
secured by said Indenture and shall have the same proportionate
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interest and share in the trust estate under the Indenture as is available to
and with all Bonds issued under the Indenture.
Section 2.02. Form of Bonds of the 2005 Series. The text of the Bonds of
the 2005 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 2005 SERIES]
No. [ ] $_____________
MAINE PUBLIC SERVICE COMPANY
First Mortgage and Collateral Trust Bond,
Series due 2005
Due April 1, 2005
MAINE PUBLIC SERVICE COMPANY, a Maine corporation (hereinafter
sometimes called the "Company"), for value received, hereby
promises to pay to or
registered assigns, on April 1, 2005 the sum of
Dollars (the "Stated Principal Amount") or, if less,
the Effective Principal Amount (as hereinafter defined) on such
date, and to pay to the registered owner hereof interest on the
Stated Principal Amount or, if less, on the Effective Principal
Amount from the date hereof at the applicable rate of interest as
set forth in, and in accordance with, the Revolving Credit
Agreement until the payment of the principal thereof.
The Bonds of the 2005 Series, including this bond, are issued
to secure the obligations of the Company under the Revolving Credit
Agreement, dated as of October 8, 1987, by and among the Company,
the signatory Banks thereto and The Bank of New York, as agent (in
such capacity, "BNY Agent"), as amended by Amendment No. 1, dated
as of October 8, 1989, Amendment No. 2, dated as of May 11, 1992,
Amendment No. 3, dated as of October 8, 1995, and Amendment No. 4,
dated as of March 28, 1997, together with any amendments,
modifications or supplements thereto, extensions, renewals,
deferrals, refunding or refinancing thereof or replacements or
successors therefor which may hereafter exist (the "Revolving
Credit Agreement"), pursuant to which the signatory Banks thereto
have each, severally, agreed, subject to the terms and conditions
thereof, to make Loans (as defined therein) evidenced by a series
of promissory notes, collectively the Notes (as defined therein),
with the obligations and liabilities (including, but not limited to, obligations
with respect to any fees, disbursements, or other expenses and indemnification)
of the Company due and to become due under the Notes or otherwise in respect of
the Revolving Credit Agreement, in each case, whether direct or indirect, joint
or several, absolute or contingent, liquidated or unliquidated, now or hereafter
existing, extended, renewed, deferred, refunded, refinanced or restructured, and
whether or not from time to time decreased or extinguished and later increased,
created or incurred, and including all
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indebtedness of the Company under any instrument now or hereafter evidencing any
of the foregoing, all being hereinafter called the "Revolving Credit
Obligations". The "Effective Principal Amount" of this bond as of the time of
any determination is an amount equal to the Revolving Credit Obligations
outstanding and unpaid at such time multiplied by a fraction, the numerator of
which is the Stated Principal Amount and the denominator of which is
$11,000,000.
The obligation of the Company to make any payment of interest
on the Bonds of the 2005 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
Revolving Credit Agreement then due and payable. The obligation of
the Company to make payments with respect to the principal of Bond
of the 2005 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 all amounts
then due with respect to Revolving Credit Obligations.
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 Chicago, Illinois, of
the Trustee under the Indenture mentioned on the reverse hereof
except that in case of the redemption as a whole at any time of the
bonds of this series then outstanding, the Company may designate in
the redemption notice other offices or agencies at which, at the
option of the registered holder, this bond may be surrendered for
redemption and payment. Interest on this bond will be payable at
the Corporate Trust Division office in the City of Chicago,
Illinois, of the Trustee, or, at the option of the holder hereof,
at the agency of the Company in the Borough of Manhattan, City and
State of New York; 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.
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IN WITNESS WHEREOF, MAINE PUBLIC SERVICE COMPANY has caused
these presents to be executed in its name and behalf by 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 2005 SERIES]
This bond constitutes the entire series designated as Bonds of
the 2005 Series, of an authorized issue of bonds of the Company,
known as First Mortgage and Collateral Trust Bonds, issued under
and equally secured (except in so far as any sinking fund,
replacement fund or other fund established in accordance with the
provisions of the Indenture hereinafter mentioned may afford
additional security for the bonds of any specific series) by an
Indenture of Mortgage and Deed of Trust dated as of October 1,
1945, duly executed and delivered by the Company to First Trust
National Association, (as successor to Continental Bank, National
Association (formerly, Continental Illinois National Bank and Trust
Company of Chicago)), as Trustee, to which Indenture of Mortgage
and Deed of Trust as supplemented and modified by indentures
supplemental thereto, including a Seventeenth Supplemental
Indenture dated as of April 1, 1997, duly executed by the Company
to said Trustee and all further 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, but not
in part, at any time, at the option of the Company prior to
maturity upon payment of the Stated Principal Amount hereof or, if
less, the Effective Principal Amount thereof on the date fixed for
redemption in the manner provided for the Indenture. In the event
that the Loans outstanding under the Revolving Credit Agreement
shall become immediately due and payable pursuant to paragraph 9 of
the Revolving Credit Agreement, this bond shall be redeemed by the
Company, on the date such Loans shall have become immediately due
and payable, at the Stated Principal Amount hereof or, if less, the
Effective Principal Amount hereof on the date fixed for redemption.
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If this bond (or any portion thereof (One Dollar or a multiple thereof))
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.
Except as may be otherwise provided in any agreement entered into pursuant
to the provisions of said Seventeenth Supplemental Indenture, in the event of
the selection for redemption of a portion only of the principal of this bond,
payment of the redemption price will be made only (a) upon presentation of this
bond for notation hereon of such payment of the portion of the principal of this
bond so called for redemption, or (b) upon surrender of this bond in exchange
for a bond or bonds of authorized denominations of the same series, for the
unredeemed balance of the principal amount of this bond.
The Indenture contains provisions permitting the Company and the Trustee,
with the consent of the holders of the not less than seventy-five percent in
principal amount of the bonds (exclusive of bonds disqualified by reason of the
Company's interest therein) at the time outstanding, including, if more than one
series of bonds shall be at the time outstanding, not less than sixty percent
in principal amount of each series affected, to effect, by an indenture
supplemental to the Indenture, modifications or alterations of the Indenture and
of the rights and obligations of the Company and of the holders of the bonds;
provided, however, that no such modification or alteration shall be made without
the written approval or consent of the registered holder hereof which will (a)
extend the maturity of this bond or reduce the rate or extend the time of
payment of interest hereon or reduce the amount of the principal hereof or (b)
permit the creation of any lien, not otherwise permitted, prior to or on a
parity with the lien of the Indenture, or (c) reduce the percentage of the
principal amount of the bonds upon the approval or consent of the holders of
which modifications or alterations may be made as aforesaid.
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 of BNY
Agent if and to the extent that BNY Agent shall have resigned as agent under the
Revolving Credit Agreement, any such transfer to be made at the principal
corporate trust office of the Trustee in the City of Chicago, Illinois, or, at
the option of such registered holder hereof, at the agency of the Company in the
Borough of Manhattan, City and State of New York, upon surrender of this bond
for cancellation and upon payment, if the Company shall so require, of the stamp
taxes and other governmental charges provided for in said Seventeenth
Supplemental Indenture, accompanied
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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.
The registered holder of this bond at his option may surrender the same for
cancellation at said office of the Trustee and receive in exchange therefor the
same aggregate principal amount of registered bonds of the same series but of
other authorized denominations upon payment, if the Company shall so require,
of the stamp taxes and other governmental charges provided for in said
Seventeenth Supplemental Indenture and subject to the terms and conditions
therein set forth.
Neither the Company nor the Trustee shall be required to make transfers or
exchanges of bonds of this series for a period of ten days next preceding any
designation of bonds of said series to be redeemed, and neither the Company nor
the Trustee shall be required to make transfers or exchanges of any bonds
designated in whole for redemption or that part of any bond designated in part
for redemption. Subject to the provisions of said Seventeenth Supplemental
Indenture, if this bond is surrendered for any transfer or exchange between the
record date for any interest payment date and such interest payment date, the
new bond will be dated such interest payment date.
The Indenture provides that in the event of any default in payment of the
interest due on any interest payment date, such interest shall not be payable
to the holder of the bond on the original record date but shall be paid to the
registered holder of such bond on the subsequent record date established for
payment of such defaulted interest.
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.
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[FORM OF TRUSTEE'S AUTHENTICATION CERTIFICATE FOR
BONDS OF THE 2005 SERIES]
This is one of the bonds, of the series designated therein,
described in the within mentioned Indenture.
FIRST TRUST NATIONAL
ASSOCIATION
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 2005 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
Revolving Credit Agreement then due and payable. The obligation of
the Company to make payments with respect to the principal of Bonds
of the 2005 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 all
amounts then due with respect to the Revolving Credit Obligations.
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 2005 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(i) of the Indenture. Upon the later of (a) the
satisfaction of all of the Revolving Credit Obligations of the
Company to BNY Agent pursuant to the Revolving Credit Agreement or
(b) the termination of the Commitments under the Revolving Credit
Agreement (as defined therein), all of the Bonds of the 2005 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 2005
Series. The Bonds of the 2005 Series shall be subject to
redemption as a whole, but not in part, at any time, at the option
of the Company prior to maturity upon payment of an amount equal to
the aggregate outstanding amount of the Bonds of the 2005 Series
(the "Stated Principal Amount") or, if less, the Revolving Credit
Obligations outstanding and unpaid on the date fixed for
redemption.
In the event that the Loans outstanding under the Revolving
Credit Agreement shall become immediately due and payable pursuant
to paragraph 9 thereof, all Bonds of the 2005 Series then
outstanding shall be redeemed by the Company, on the date such
Loans shall have become immediately due and payable, at a
redemption price equal to the Stated Principal
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Amount thereof or, if less, the Revolving Credit Obligations outstanding and
unpaid on the date fixed for redemption.
The Trustee may conclusively presume that no redemption of
Bonds of the 2005 Series is required pursuant to this Section 2.04
unless and until the Trustee shall have received a written notice
from BNY Agent as described in Section 12.01(i) of the Indenture.
Said notice shall also contain a waiver of notice of such
redemption by BNY Agent as holder of all of the Bonds of the 2005
Series then outstanding.
No notice of redemption pursuant to Section 10.02 of the
Indenture need be given if the holders of all Bonds of the 2005
Series called for redemption waive notice thereof in writing and
such waiver is filed with the Trustee.
SECTION 2.05. Bondholders' List. Notwithstanding the provisions of
Section 11.02(B) of the Original Indenture, any one of the holders of the Bonds
of the 2005 Series shall be entitled to make application to the Trustee for a
Bondholders' list as provided for in Section 11.02.
SECTION 2.06. Mutilated, Lost or Destroyed Bonds. Notwithstanding the
provisions of Section 2.12 of the Original Indenture, for so long as any holder
of Bonds of the 2005 Series shall be an institutional holder, an unsecured
indemnity provided by such holder shall be deemed acceptable for purposes of
requesting a replacement bond for a mutilated, lost or destroyed Bond of the
2005 Series.
Section 2.07 Duration of Effectiveness of Article Two. This Article
shall be of force and effect only so long as any Bonds of the 2005 Series are
outstanding.
ARTICLE THREE
Modification of the Indenture
Section 3.01. Section 15.09 of the Indenture is hereby amended by adding
a new paragraph at the end of said Section which reads as follows:
"The Trustee shall, as promptly as practicable but
in no event later than the third (3rd) business day
following delivery to the Trustee of a notice described
in clause A. or B. of 33 Maine Revised Statutes
("M.R.S.") Section 505 5. (i.e. from (a) the Company to
the effect that the Company is limiting the amount of
future advances to be secured by the Bonds of the 2005
Series to not less than the amount actually advanced as
of the end of the third (3rd) business day following
delivery of such notice to the Trustee or (b) a person
described in clause B of said Section of M.R.S. stating
that future advances made after the end of the third
(3rd) business day following receipt of such notice by
the Trustee are junior to
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such person's rights in or liens upon the trust estate under the
Indenture), give to the holder of the Bonds of the 2005 Series, in the
manner and to the extent provided in Subsection C of Section
11.04 of the Indenture (except that if the holder of the
Bonds of the 2005 Series shall have provided the Trustee
with information to provide such notice by facsimile,
such notice shall be sent by facsimile), notice of the
receipt of such notice."
Section 3.02. Section 12.01 of the Indenture is hereby amended by adding
new clause (i) thereto which reads as follows:
"(i) so long as any of the Bonds of the 2005 Series are
outstanding, upon receipt by the Trustees of a notice
from the holder of the Bonds of the 2005 Series that an
event of default under the Revolving Credit Agreement has
occurred and is continuing;"
Section 3.03. Duration of Effectiveness of Article Three. This Article
shall be of force and effect only so long as any Bonds of the 2005 Series are
outstanding.
ARTICLE FOUR
Authentication and Delivery of Bonds of the 2005 Series
Section 4.01. Upon the execution and delivery of this
Seventeenth Supplemental Indenture, Bonds of the 2005 Series in the
aggregate amount of Eleven Million Dollars ($11,000,000) 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. Additional Bonds of the 2005
Series may be executed, authenticated and delivered from time to
time as permitted by the provisions of Article Five of the Original
Indenture.
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.
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Section 5.02. This Seventeenth 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 Seventeenth 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 Seventeenth 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 Seventeenth 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 Seventeenth 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
Seventeenth 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 Seventeenth Supplemental Indenture are inserted for
convenience only.
Section 5.07. All the covenants, stipulations, promises and
agreements in this Seventeenth 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 Seventeenth Supplemental
Indenture is dated for convenience and for the purpose of reference
as of April 1, 1997, 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 Seventeenth Supplemental Indenture, the same may be
simultaneously executed in several counterparts, each
-24-
of which shall be deemed to be an original, and such counterparts shall
together constitute but one and the same instrument.
-25-
IN WITNESS WHEREOF, MAINE PUBLIC SERVICE COMPANY has caused
this Seventeenth 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
FIRST TRUST NATIONAL ASSOCIATION in token of its acceptance of the
trust hereby created has caused this Seventeenth 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, all as of the day and year
first above written.
MAINE PUBLIC SERVICE COMPANY
/s/
Name:Larry LaPlante
Title:Vice President
CORPORATE SEAL
Attest:
/s/
Name: Kurt A. Tornquist
Title: Assistant Secretary
Signed, sealed and delivered
by MAINE PUBLIC SERVICE COMPANY
in the presence of:
/s/
Marilyn L. Bouchard
/s/
Richard C. Hatch
-26-
FIRST TRUST NATIONAL
ASSOCIATION
/s/
Name:Patricia M. Trlak
Title:Vice President
CORPORATE SEAL
Attest:
/s/
Name: Larry Kusch
Title: Assistant Secretary
Signed, sealed and delivered
by FIRST TRUST NATIONAL
ASSOCIATION in the presence of:
/s/
Name: Harry H. Hall
Title: Vice President
-27-
STATE OF MAINE )
: ss.:
COUNTY OF AROOSTOOK )
April 28, 1997
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/
Notary Public
Alice E. Shepard
Notary Public, Maine
My Commission Expires October 29, 2000
NOTARIAL SEAL
-28-
STATE OF NEW YORK )
: ss.:
COUNTY OF RICHMOND )
April 30, 1997
Then personally appeared the above-named Patricia Trlak, a
Vice President of First Trust National Association 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/
Notary Public
P. Johnson
Notary Public, Cook County, Illinois
My Commission expires June 28, 1997
NOTARIAL SEAL
-29-
Exhibit 4(u)
THIS INSTRUMENT GRANTS A SECURITY INTEREST
BY A TRANSMITTING UTILITY
THIS INSTRUMENT CONTAINS AFTER-ACQUIRED PROPERTY PROVISIONS
MAINE PUBLIC SERVICE COMPANY
TO
U.S. BANK TRUST
NATIONAL ASSOCIATION
Trustee
EIGHTEENTH SUPPLEMENTAL INDENTURE
Dated as of April 1, 1998
Supplementing and Modifying Indenture of Mortgage and
Deed of Trust dated as of October 1, 1945
and
Relating to an Issue of Mortgage and
Collateral Trust Bonds, Series due 1999
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 EIGHTEENTH SUPPLEMENTAL INDENTURE (hereinafter called the
"Eighteenth Supplemental Indenture"), dated as of April 1, 1998,
made by MAINE PUBLIC SERVICE COMPANY, a Maine corporation
(hereinafter called the "Company"), party of the first part, and
U.S. BANK TRUST NATIONAL ASSOCIATION (formerly known as First Trust
National Association, as successor to CONTINENTAL BANK, NATIONAL
ASSOCIATION (formerly, Continental Illinois National Bank and Trust
Company of Chicago)), a national banking association duly organized
and existing under the laws of the United States of America, and
having its principal place of business in the City of Chicago,
State of Illinois (hereinafter called the "Trustee"), party of the
second part.
WHEREAS, the Company has heretofore executed and delivered to
the Trustee an Indenture of Mortgage and Deed of Trust, dated as of
October 1, 1945 (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 "First 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 an initial series of Bonds designated
as "First Mortgage and Collateral Trust Bonds, 2 7/8% Series due
1975" (herein sometimes called "Bonds of the 1975 Series"); and
WHEREAS, the Company has heretofore executed and delivered to
the Trustee a First Supplemental Indenture, dated as of September
1, 1950, pursuant to which the Company provided for the creation of
a second series of Bonds designated as "First Mortgage and
Collateral Trust Bonds, 3% Series due 1980" (herein sometimes
called "Bonds of the 1980 Series"), a Second Supplemental
Indenture, dated as of February 1, 1955, pursuant to which the
Company provided for the creation of a third series of Bonds
designated as "First Mortgage and Collateral Trust Bonds, 3.35%
Series due 1985" (herein sometimes called "Bonds of the 1985
Series"), a Third Supplemental Indenture, dated as of September 1,
1960, pursuant to which the Company provided for the creation of a
fourth series of Bonds designated as "First Mortgage and Collateral
Trust Bonds, 5 1/2% Series due 1990" (herein sometimes called
"Bonds of the 1990 Series"), a Fourth Supplemental Indenture, dated
as of January 1, 1965, pursuant to which the Company provided for
the creation of a fifth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 4 3/4% Series due 1995"
(herein sometimes called "Bonds of the 1995 Series"), a Fifth
Supplemental Indenture, dated as of May 1, 1968, pursuant to which
the Company provided for the creation of a sixth series of Bonds
designated as "First Mortgage and Collateral Trust Bonds, 7 1/8%
Series due 1998" (herein sometimes called "Bonds of the 1998
Series"), a Sixth Supplemental Indenture, dated as of March 1,
1973, pursuant to which the Company supplemented and modified the
Original Indenture and provided for the creation of a seventh
series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, 7.95% Series due 2003" (herein sometimes called "Bonds of
the 2003 Series"), a Seventh Supplemental Indenture, dated as of
September 1, 1975, pursuant to which the Company supplemented and
modified the Original Indenture and provided for the creation of an
eighth series of Bonds designated as "First Mortgage and Collateral
Trust Bonds, 10 5/8% Series due 1995" (herein sometimes called
"Bonds of the Second 1995 Series"), an Eighth Supplemental
Indenture, dated as of January 1, 1977, pursuant to which the
Company supplemented the Original Indenture, a Ninth Supplemental
Indenture, dated as of March 1, 1978, pursuant to which the Company
supplemented and modified the Original Indenture, a Tenth
Supplemental Indenture, dated as of October 1, 1979, pursuant to
which the Company supplemented the Original Indenture and provided
for the creation of a ninth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 10 1/4% Series due 2004"
(herein sometimes called "Bonds of the 2004 Series"), an Eleventh
Supplemental Indenture, dated as of January 15, 1983, pursuant to
which the Company supplemented the Original Indenture and provided
for the creation of a tenth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 13 7/8% Series due 1992"
(herein sometimes called "Bonds of the 1992 Series"), a Twelfth
Supplemental Indenture, dated as of July 1, 1984, pursuant to which
the Company supplemented the Original Indenture and provided for
the creation of an eleventh series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 16.30% Series due 1989"
(herein sometimes called "Bonds of the 1989 Series"), a Thirteenth
Supplemental Indenture, dated as of July 1, 1984, pursuant to which
the Company supplemented the Original Indenture and provided for
the creation of a twelfth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, Floating Rate Series A due
1985" (herein sometimes called "Bonds of the Series A due 1985"),
a Fourteenth Supplemental Indenture, dated as of July 1, 1985,
pursuant to which the Company supplemented the Original Indenture
and provided for the creation of a thirteenth series of Bonds
designated as "First Mortgage and Collateral Trust Bonds, Floating
Rate Series B due 1986" (herein sometimes called "Bonds of the
Series B due 1986"), a Fifteenth Supplemental Indenture, dated as
of March 1, 1986, pursuant to which the Company supplemented the
Original Indenture and provided for the creation of a fourteenth
series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, 11% Series due 1996" (herein sometimes called "Bonds of the
1996 Series"), a Sixteenth Supplemental Indenture, dated as of
September 1, 1991, pursuant to which the Company supplemented the
Original Indenture and provided for the creation of a fifteenth
series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, 9.775% Series due 2011" (herein sometimes called "Bonds of
the 2011 Series"), and a Seventeenth Supplemental Indenture, dated
as of April 1, 1997, pursuant to which the Company supplemented the
Original Indenture and provided for the creation of a sixteenth
series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, Series due 2005" (herein sometimes called "Bonds of the 2005
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 First Mortgage and
Collateral Trust Bonds of series and in principal amounts as
follows:
Issued Outstanding
Bonds of the 1998 Series $4,000,000 $2,920,000
Bonds of the 2003 Series 2,500,000 1,900,000
Bonds of the 2005 Series 11,000,000 11,000,000
Bonds of the 2011 Series 15,000,000 15,000,000
which constitute the only Bonds outstanding under the Original
Indenture, as so supplemented and modified; and
-2-
WHEREAS, the Company now desires to create a new series of
Bonds to be designated First Mortgage and Collateral Trust Bonds,
Series due 1999 (herein sometimes called the "Bonds of the 1999
Series"), and the Original Indenture provides that each series of
Bonds (except the Bonds of the 1975 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 Seventeenth 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 1999 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
Eighteenth Supplemental Indenture, a valid and binding mortgage and
deed of trust 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 Eighteenth Supplemental Indenture
and the issue of the Bonds of the 1999 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 Eighteenth Supplemental Indenture (the
Original Indenture, as supplemented by the First, Second, Third,
Fourth, Fifth, Eighth, Tenth, Eleventh, Twelfth, Thirteenth,
Fourteenth, Fifteenth and Sixteenth Supplemental Indentures, as
supplemented and modified by the Sixth, Seventh, Ninth and
Seventeenth Supplemental Indentures and as supplemented and
modified by this Eighteenth 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 trust under the Original Indenture, as supplemented and
modified, as follows:
-3-
ARTICLE ONE
Schedule of Mortgaged Property.
SECTION 1.01. In order to further secure the payment of the
principal of, premium, if 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 Eighteenth 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 Eighteenth Supplemental Indenture and
by these presents does grant, bargain, sell, alien, remise,
release, convey, assign, transfer, mortgage, pledge, set over and
confirm unto U.S. Bank Trust National Association, as Trustee under
the Indenture, and to its assigns forever, all property, real,
personal or mixed, acquired since the execution and delivery of the
Seventeenth 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 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:
Harold & Theodore Sherman 8/8/97 3021 044 Houlton
Edith A. Dwyer 8/8/97 3021 040 Houlton
Norman Grant III 9/15/97 3060 152 Houlton
Dale Hosford 10/28/97 3075 330 Houlton
Edith A. Dwyer 12/18/97 3090 319 Houlton
-4-
ADDITIONAL RIGHT-OF-WAY, ROUTE 11 REBUILD, SO CALLED
A 34,500 volt transmission line in Aroostook County, Maine
owned and operated by Maine Public Service Company from junction of
Rt. 163 & Rt. 11 in Ashland, Maine and southerly along Rt. 11, a
distance of approximately 2.05 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:
Hazen Stevens 4/3/97 2998 109 Houlton
Hazen Stevens 5/22/97 3016 154 Houlton
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 apparatuses, 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,
-5-
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 reversions, 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":
-6-
(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 VII 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
VII; and
(b) All property which prior to the execution and
delivery of this Eighteenth 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, as modified by the provisions of the
Sixth Supplemental Indenture, the Seventh Supplemental Indenture,
the Ninth Supplemental Indenture and the Seventeenth Supplemental
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
-7-
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 1999 Series and Certain
Provisions Relating Thereto
Section 2.01. Terms of the Bonds of the 1999 Series. There
shall be a series of Bonds, known as and entitled "First Mortgage
and Collateral Trust Bonds, Series due 1999" (herein referred to as
the "Bonds of the 1999 Series"), and the form thereof shall be
substantially as hereinafter set forth in Section 2.02.
The Bonds of the 1999 Series are issued to secure the
obligations of the Company under the Revolving Credit Agreement,
dated as of October 8, 1987, by and among the Company, the
signatory Banks thereto and The Bank of New York, as agent (in such
capacity, "BNY Agent"), as amended by Amendment No. 1, dated as of
October 8, 1989, Amendment No. 2, dated as of May 11, 1992,
Amendment No. 3, dated as of October 8, 1995, Amendment No. 4,
dated as of March 28, 1997, and Amendment No. 5, dated as of March
31, 1998, together with any amendments, modifications or
supplements thereto, extensions, renewals, deferrals, refunding or
refinancing thereof or replacements or successors therefor which
may hereafter exist (the "Revolving Credit Agreement"), pursuant to
which the signatory Banks thereto have each, severally, agreed,
subject to the terms and conditions thereof, to make Loans (as
defined therein) evidenced by a series of promissory notes,
collectively the Notes (as defined therein), with the obligations
and liabilities (including, but not limited to, obligations with
respect to any fees, disbursements, or other expenses and
indemnification) of the Company due and to become due under the
Notes or otherwise in respect of the Revolving Credit Agreement, in
each case, whether direct or indirect, joint or several, absolute
or contingent, liquidated or unliquidated, now or hereafter
existing, extended, renewed, deferred, refunded, refinanced or
restructured, and whether or not from time to time decreased or
extinguished and later increased, created or incurred, and
including all indebtedness of the Company under any instrument now
or hereafter evidencing any of the foregoing, all being hereinafter
called the "Revolving Credit Obligations".
The aggregate principal amount of the Bonds of the 1999 Series
which may be authenticated and delivered and outstanding under this
Eighteenth Supplemental Indenture shall be limited to $2,000,000
except for duplicate Bonds, authenticated and delivered pursuant to
Section 2.12 of the Original Indenture. The definitive Bonds of
the 1999 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.
-8-
The date of authentication on the original issuance of the
Bonds of the 1999 Series shall be the date of commencement of the
first interest period for such Bonds. All Bonds of the 1999 Series
shall mature June 30, 1999, and shall bear interest at the
applicable rate of interest as set forth in, and in accordance
with, the Revolving Credit Agreement until the payment of the
principal thereof. Both principal of and interest on the Bonds of
the 1999 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 Chicago, Illinois, of the Trustee or, at the office of
its successor as Trustee, except that, in case of the redemption as
a whole at any time of Bonds of the 1999 Series then outstanding,
the Company may designate in the redemption notice other offices or
agencies at which, at the option of the registered holders, Bonds
of the 1999 Series may be surrendered for redemption and payment;
and in the case of interest on Bonds of the 1999 Series, at the
option of the registered holder, at the agency of the Company in
the Borough of Manhattan, City and State of New York, in each case
to the holder of record on the record date as hereinbelow defined.
Interest on the Bonds of the 1999 Series shall, unless otherwise
directed by the respective registered holders thereof, be paid by
checks payable to the order of the respective holders entitled
thereto, and mailed by the Trustee by first class mail, postage
prepaid, to such holders at their respective registered addresses
as shown on the Bond register for the Bonds of the 1999 Series.
The definitive Bonds of the 1999 Series may be issued in the
form of Bonds engraved, printed or lithographed on steel engraved
borders and the signature of the President, or a Vice President and
of the Secretary or an Assistant Secretary of the Company may be
facsimile. Bonds of the 1999 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.
Notwithstanding any provision in the Original Indenture to the
contrary, the person in whose name any Bond of the 1999 Series is
registered at the close of business on any record date (as
hereinbelow defined) with respect to any interest payment date
shall be entitled to receive the interest payable on such interest
payment date notwithstanding the cancellation of such Bond of the
1999 Series upon any transfer or exchange thereof (including any
exchange effected as an incident to a partial redemption thereof)
subsequent to the record date and prior to such interest payment
date, except that, if and to the extent that the Company shall
default in the payment of the interest due on such interest payment
date, then the registered holders of Bonds of the 1999 Series on
such record date shall have no further right to or claim in respect
of such defaulted interest as such registered holders on such
record date, and the persons entitled to receive payment of any
defaulted interest thereafter payable or paid on any Bonds of the
1999 Series shall be the registered holders of such Bonds of the
1999 Series on the record date for payment of such defaulted
interest. The term "record date" as used in this Section 2.01, and
in the form of the Bonds of the 1999 Series, with respect to any
interest payment date applicable to the Bonds of the 1999 Series,
shall mean the June 15 next preceding a June 30 interest
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payment date or the December 15 next preceding a December 30 interest
payment date, as the case may be, or a special record date
established for defaulted interest as hereinafter provided.
In the case of failure by the Company to pay any interest when
due, the claim for such interest shall be deemed to have been
transferred by transfer of any Bond of the 1999 Series registered
on the Bond register, and the Company by not less than 10 days
written notice to bondholders may fix a subsequent record date, not
more than 15 days prior to the date fixed for the payment of such
interest, for determination of holders entitled to payment of such
interest. Such provision for establishment of a subsequent record
date, however, shall in no way affect the rights of bondholders or
of the Trustee consequent on any default.
Except as provided in this Section 2.01, every Bond of the
1999 Series shall be dated as provided in Section 2.05 of the
Original Indenture except that upon original issuance of the Bonds
of the 1999 Series, the Bonds of the 1999 Series shall be dated the
date of authentication. Notwithstanding any provision in the
Original Indenture to the contrary, so long as there is no existing
default in the payment of interest on the Bonds of the 1999 Series,
all Bonds of the 1999 Series authenticated by the Trustee between
the record date for any interest payment date and such interest
payment date shall be dated such interest payment date and shall
bear interest from such interest payment date.
As permitted by the provisions of Section 2.10 of the Original
Indenture and upon payment at the option of the Company of a sum
sufficient to reimburse it for any stamp tax or other governmental
charge as provided in Section 2.11 of the Original Indenture, Bonds
of the 1999 Series may be exchanged for other Bonds of the 1999
Series of different authorized denominations of like aggregate
principal amount. Notwithstanding the provisions of Section 2.11
or the last sentence of the first paragraph of Section 2.12 of the
Original Indenture, no further sum, other than the sum sufficient
to reimburse the Company for any stamp taxes or other governmental
charges, shall be required to be paid upon any exchange or
replacement of Bonds of the 1999 Series or upon any transfer
thereof.
The Bonds of the 1999 Series shall be nontransferable prior to
maturity except upon the prior written consent of the Company or to
effect transfer to any successor of BNY Agent if BNY Agent shall
have resigned as agent under the Revolving Credit Agreement, any
such transfer to be made at the principal corporate trust office of
the Trustee in the City of Chicago, Illinois, upon surrender and
cancellation of such Bonds of the 1999 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 1999
Series or by his duly authorized attorney, and thereupon a new Bond
of the 1999 Series, for a like principal amount, will be issued to
the successor 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 1999 Series.
Notwithstanding any provision in the Original Indenture to the
contrary, neither the Company nor the Trustee shall be required to
make transfers or exchanges of Bonds of the 1999
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Series for a period of ten days next preceding any designation of the Bonds of
the 1999 Series to be redeemed and neither the Company nor the
Trustee shall be required to make transfers or exchanges of any
bonds designated in whole for redemption or that part of any bond
designated in part for redemption.
The Bonds of the 1999 Series, limited as provided in
Section 2.01 hereof to $2,000,000 in aggregate principal amount,
shall be issued to BNY Agent for the purpose, together with the
Bonds of the 2005 Series, of securing the Revolving Credit
Obligations, including, without limitation, any future advances or
protective advances made under the Revolving Credit Agreement (with
the terms "future advances" and "protective advances" having the
meanings ascribed to such terms in 33 Maine Revised Statutes
Section 505.1), to the same extent as if such future advances were
made on the date hereof and with the understanding that the
Revolving Credit Obligations may decrease or increase from time to
time. The Bonds of the 1999 Series securing said Revolving Credit
Obligations (including such future advances and such protective
advances) shall have the same right, lien and privilege under the
Indenture and shall be equally secured by said Indenture and shall
have the same proportionate interest and share in the trust estate
under the Indenture as is available to and with all Bonds issued
under the Indenture.
Section 2.02. Form of Bonds of the 1999 Series. The text of
the Bonds of the 1999 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 1999 SERIES]
No. [ ] $_____________
MAINE PUBLIC SERVICE COMPANY
First Mortgage and Collateral Trust Bond,
Series due 1999
Due June 30, 1999
MAINE PUBLIC SERVICE COMPANY, a Maine corporation (hereinafter
sometimes called the "Company"), for value received, hereby promises to pay to
or registered assigns, on June 30, 1999 the sum of
Dollars (the "Stated Principal Amount") or, if less, the Effective
Principal Amount (as hereinafter defined) on such date, and to pay to the
registered owner hereof interest on the Stated Principal Amount or, if less, on
the Effective Principal Amount from the date hereof at the applicable rate of
interest as set forth in, and in accordance with, the Revolving Credit Agreement
(as hereinafter defined) until the payment of the principal thereof.
The Bonds of the 1999 Series, including this bond, are issued
to secure the obligations of the Company under the Revolving Credit
Agreement, dated as of October 8, 1987, by and
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among the Company, the signatory Banks thereto and The Bank of New York, as
agent (in such capacity, "BNY Agent"), as amended by Amendment No. 1, dated
as of October 8, 1989, Amendment No. 2, dated as of May 11, 1992,
Amendment No. 3, dated as of October 8, 1995, Amendment No. 4,
dated as of March 28, 1997, and Amendment No. 5, dated as of March
31, 1998, together with any amendments, modifications or
supplements thereto, extensions, renewals, deferrals, refunding or
refinancing thereof or replacements or successors therefor which
may hereafter exist (the "Revolving Credit Agreement"), pursuant to
which the signatory Banks thereto have each, severally, agreed,
subject to the terms and conditions thereof, to make Loans (as
defined therein) evidenced by a series of promissory notes,
collectively the Notes (as defined therein), with the obligations
and liabilities (including, but not limited to, obligations with
respect to any fees, disbursements, or other expenses and
indemnification) of the Company due and to become due under the
Notes or otherwise in respect of the Revolving Credit Agreement, in
each case, whether direct or indirect, joint or several, absolute
or contingent, liquidated or unliquidated, now or hereafter
existing, extended, renewed, deferred, refunded, refinanced or
restructured, and whether or not from time to time decreased or
extinguished and later increased, created or incurred, and
including all indebtedness of the Company under any instrument now
or hereafter evidencing any of the foregoing, all being hereinafter
called the "Revolving Credit Obligations". The "Effective
Principal Amount" of this bond as of the time of any determination
is an amount equal to the excess, if any, of (i) the Revolving
Credit Obligations outstanding and unpaid at such time over (ii)
$11,000,000 multiplied by a fraction, the numerator of which is the
Stated Principal Amount and the denominator of which is $2,000,000.
The obligation of the Company to make any payment of interest
on the Bonds of the 1999 Series, when such interest shall be due
and payable (including, but not limited to, on June 30, 1999),
shall be deemed to be, and shall be, satisfied and discharged if
the Company shall have paid all interest under the Revolving Credit
Agreement then due and payable. The obligation of the Company to
make payments with respect to the principal of the Bonds of the
1999 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 (including, but not limited to, on June 30,
1999), the Company shall have paid all amounts then due with
respect to Revolving Credit Obligations.
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 Chicago, Illinois, of
the Trustee under the Indenture mentioned on the reverse hereof
except that in case of the redemption as a whole at any time of the
bonds of this series then outstanding, the Company may designate in
the redemption notice other offices or agencies at which, at the
option of the registered holder, this bond may be surrendered for
redemption and payment. Interest on this bond will be payable at
the Corporate Trust Division office in the City of Chicago,
Illinois, of the Trustee, or, at the option of the holder hereof,
at the agency of the Company in the Borough of Manhattan, City and
State of New York; 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
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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 by 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 1999 SERIES]
This bond constitutes the entire series designated as Bonds of
the 1999 Series, of an authorized issue of bonds of the Company,
known as First Mortgage and Collateral Trust Bonds, issued under
and equally secured (except in so far as any sinking fund,
replacement fund or other fund established in accordance with the
provisions of the Indenture hereinafter mentioned may afford
additional security for the bonds of any specific series) by an
Indenture of Mortgage and Deed of Trust dated as of October 1,
1945, duly executed and delivered by the Company to U.S. Bank Trust
National Association (formerly known as First Trust National
Association, as successor to Continental Bank, National Association
(formerly, Continental Illinois National Bank and Trust Company of
Chicago)), as Trustee, to which Indenture of Mortgage and Deed of
Trust as supplemented and modified by indentures supplemental
thereto, including an Eighteenth Supplemental Indenture dated as of
April 1, 1998, duly executed by the Company to said Trustee and all
further 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.
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This bond shall be subject to redemption as a whole, but not
in part, at any time, at the option of the Company prior to
maturity upon payment of the Stated Principal Amount hereof or, if
less, the Effective Principal Amount thereof on the date fixed for
redemption in the manner provided for in the Indenture. In the
event that the Loans outstanding under the Revolving Credit
Agreement shall become immediately due and payable pursuant to
paragraph 9 of the Revolving Credit Agreement, this bond shall be
redeemed by the Company, on the date such Loans shall have become
immediately due and payable, at the Stated Principal Amount hereof
or, if less, the Effective Principal Amount hereof on the date
fixed for redemption.
If this bond (or any portion thereof (One Dollar or a multiple
thereof)) 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.
Except as may be otherwise provided in any agreement entered
into pursuant to the provisions of said Eighteenth Supplemental
Indenture, in the event of the selection for redemption of a
portion only of the principal of this bond, payment of the
redemption price will be made only (a) upon presentation of this
bond for notation hereon of such payment of the portion of the
principal of this bond so called for redemption, or (b) upon
surrender of this bond in exchange for a bond or bonds of
authorized denominations of the same series, for the unredeemed
balance of the principal amount of this bond.
The Indenture contains provisions permitting the Company and
the Trustee, with the consent of the holders of the not less than
seventy-five percent in principal amount of the bonds (exclusive of
bonds disqualified by reason of the Company's interest therein) at
the time outstanding, including, if more than one series of bonds
shall be at the time outstanding, not less than sixty percent in
principal amount of each series affected, to effect, by an
indenture supplemental to the Indenture, modifications or
alterations of the Indenture and of the rights and obligations of
the Company and of the holders of the bonds; provided, however,
that no such modification or alteration shall be made without the
written approval or consent of the registered holder hereof which
will (a) extend the maturity of this bond or reduce the rate or
extend the time of payment of interest hereon or reduce the amount
of the principal hereof or (b) permit the creation of any lien, not
otherwise permitted, prior to or on a parity with the lien of the
Indenture, or (c) reduce the percentage of the principal amount of
the bonds upon the approval or consent of the holders of which
modifications or alterations may be made as aforesaid.
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.
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This bond is nontransferable prior to its maturity except upon
the prior written consent of the Company or to effect transfer to
any successor of BNY Agent if and to the extent that BNY Agent
shall have resigned as agent under the Revolving Credit Agreement,
any such transfer to be made at the principal corporate trust
office of the Trustee in the City of Chicago, Illinois, or, at the
option of such registered holder hereof, at the agency of the
Company in the Borough of Manhattan, City and State of New York,
upon surrender of this bond for cancellation and upon payment, if
the Company shall so require, of the stamp taxes and other
governmental charges provided for in said Eighteenth Supplemental
Indenture, 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.
The registered holder of this bond at his option may surrender
the same for cancellation at said office of the Trustee and receive
in exchange therefor the same aggregate principal amount of
registered bonds of the same series but of other authorized
denominations upon payment, if the Company shall so require, of the
stamp taxes and other governmental charges provided for in said
Eighteenth Supplemental Indenture and subject to the terms and
conditions therein set forth.
Neither the Company nor the Trustee shall be required to make
transfers or exchanges of bonds of this series for a period of ten
days next preceding any designation of bonds of said series to be
redeemed, and neither the Company nor the Trustee shall be required
to make transfers or exchanges of any bonds designated in whole for
redemption or that part of any bond designated in part for
redemption. Subject to the provisions of said Eighteenth
Supplemental Indenture, if this bond is surrendered for any
transfer or exchange between the record date for any interest
payment date and such interest payment date, the new bond will be
dated such interest payment date.
The Indenture provides that in the event of any default in
payment of the interest due on any interest payment date, such
interest shall not be payable to the holder of the bond on the
original record date but shall be paid to the registered holder of
such bond on the subsequent record date established for payment of
such defaulted interest.
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 these
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
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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 1999 SERIES]
This is one of the bonds, of the series designated therein,
described in the within mentioned Indenture.
U.S. BANK TRUST NATIONAL
ASSOCIATION
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 1999 Series, when such interest shall be due and
payable (including, but not limited to, June 30, 1999), shall be
deemed to be, and shall be, satisfied and discharged if the Company
shall have paid all interest under the Revolving Credit Agreement
then due and payable. The obligation of the Company to make
payments with respect to the principal of Bonds of the 1999 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 (including, but not limited to, June 30, 1999), the Company
shall have paid BNY Agent all amounts then due with respect to the
Revolving Credit Obligations. 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 1999 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(i) of the Indenture. Upon the
later of (a) the satisfaction of all of the Revolving Credit
Obligations of the Company to BNY Agent pursuant to the Revolving
Credit Agreement or (b) the termination of the Commitments under
the Revolving Credit Agreement (as defined therein), all of the
Bonds of the 1999 Series shall be surrendered by BNY Agent to the
Trustee for cancellation, and upon such surrender shall be deemed
fully paid.
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Section 2.04. Redemption Provisions for the Bonds of the 1999
Series. The Bonds of the 1999 Series shall be subject to
redemption as a whole, but not in part, at any time, at the option
of the Company prior to maturity upon payment of the Stated
Principal Amount thereof or, if less, the Effective Principal
Amount thereof including interest accrued thereon to the redemption
date.
In the event that the Loans outstanding under the Revolving
Credit Agreement shall become immediately due and payable pursuant
to paragraph 9 thereof, all Bonds of the 1999 Series then
outstanding shall be redeemed by the Company, on the date such
Loans shall have become immediately due and payable, at a
redemption price equal to the Stated Principal Amount thereof or,
if less, the Effective Principal Amount thereof including interest
accrued thereon to the redemption date.
The Trustee may conclusively presume that no redemption of
Bonds of the 1999 Series is required pursuant to this Section 2.04
unless and until the Trustee shall have received a written notice
from BNY Agent as described in Section 12.01(j) of the Indenture.
Said notice shall also contain a waiver of notice of such
redemption by BNY Agent as holder of all of the Bonds of the 1999
Series then outstanding.
No notice of redemption pursuant to Section 10.02 of the
Indenture need be given if the holders of all Bonds of the 1999
Series called for redemption waive notice thereof in writing and
such waiver is filed with the Trustee.
SECTION 2.05. Bondholders' List. Notwithstanding the
provisions of Section 11.02(B) of the Original Indenture, any one
of the holders of the Bonds of the 1999 Series shall be entitled to
make application to the Trustee for a Bondholders' list as provided
for in Section 11.02.
SECTION 2.06. Mutilated, Lost or Destroyed Bonds.
Notwithstanding the provisions of Section 2.12 of the Original
Indenture, for so long as any holder of Bonds of the 1999 Series
shall be an institutional holder, an unsecured indemnity provided
by such holder shall be deemed acceptable for purposes of
requesting a replacement bond for a mutilated, lost or destroyed
Bond of the 1999 Series.
Section 2.07 Duration of Effectiveness of Article Two. This
Article shall be of force and effect only so long as any Bonds of
the 1999 Series are outstanding.
ARTICLE THREE
Modification of the Indenture
Section 3.01. Section 15.09 of the Indenture is hereby amended
by adding a new paragraph at the end of said Section which reads as
follows:
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"The Trustee shall, as promptly as practicable but
in no event later than the third (3rd) business day
following delivery to the Trustee of a notice described
in clause A. or B. of 33 Maine Revised Statutes
("M.R.S.") Section 505 5. (i.e. from (a) the Company to
the effect that the Company is limiting the amount of
future advances to be secured by the Bonds of the 1999
Series to not less than the amount actually advanced as
of the end of the third (3rd) business day following
delivery of such notice to the Trustee or (b) a person
described in clause B of said Section of M.R.S. stating
that future advances made after the end of the third
(3rd) business day following receipt of such notice by
the Trustee are junior to such person's rights in or
liens upon the trust estate under the Indenture), give to
the holder of the Bonds of the 1999 Series, in the manner
and to the extent provided in Subsection C of Section
11.04 of the Indenture (except that if the holder of the
Bonds of the 1999 Series shall have provided the Trustee
with information to provide such notice by facsimile,
such notice shall be sent by facsimile), notice of the
receipt of such notice."
Section 3.02. Section 12.01 of the Indenture is hereby amended
by adding new clause (j) thereto which reads as follows:
"(j) so long as any of the Bonds of the 1999 Series are
outstanding, upon receipt by the Trustees of a notice
from the holder of the Bonds of the 1999 Series that an
event of default under the Revolving Credit Agreement has
occurred and is continuing;"
Section 3.03. Duration of Effectiveness of Article Three.
This Article shall be of force and effect only so long as any Bonds
of the 1999 Series are outstanding.
ARTICLE FOUR
Authentication and Delivery of Bonds of the 1999 Series
Section 4.01. Upon the execution and delivery of this
Eighteenth Supplemental Indenture, Bonds of the 1999 Series in the
aggregate amount of Two Million Dollars ($2,000,000) 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. Additional Bonds of the 1999 Series may be
executed, authenticated and delivered from time to time as
permitted by the provisions of Article Five of the Original
Indenture.
ARTICLE FIVE
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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 Eighteenth 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 Eighteenth
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 Eighteenth 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 Eighteenth 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 Eighteenth 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
Eighteenth 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 Eighteenth Supplemental Indenture are inserted for
convenience only.
Section 5.07. All the covenants, stipulations, promises and
agreements in this Eighteenth 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.
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Section 5.08. Although this Eighteenth Supplemental Indenture
is dated for convenience and for the purpose of reference as of
April 1, 1998, 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 Eighteenth 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.
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IN WITNESS WHEREOF, MAINE PUBLIC SERVICE COMPANY has caused
this Eighteenth 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
U.S. BANK TRUST NATIONAL ASSOCIATION in token of its acceptance of
the trust hereby created has caused this Eighteenth 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, 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/ Kurt A. Tornquist
Name: Kurt A. Tornquist
Title: Assistant Secretary
Signed, sealed and delivered
by MAINE PUBLIC SERVICE COMPANY
in the presence of:
/s/ Marilyn L. Bouchard
Marilyn L. Bouchard
/s/ Alice E. Shepard
Alice E. Shepard
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U.S. BANK TRUST NATIONAL
ASSOCIATION
/s/ Patricia M. Trlak
Name:Patricia M. Trlak
Title:Vice President
CORPORATE SEAL
Attest:
/s/ Larry Kusch
Name: Larry Kusch
Title: Assistant Secretary
Signed, sealed and delivered
by U.S. BANK TRUST NATIONAL
ASSOCIATION in the presence of:
/s/ Harry H. Hall
Name: Harry H. Hall
Title: Vice President
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STATE OF MAINE )
: ss.:
COUNTY OF AROOSTOOK )
May 26, 1998
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
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STATE OF ILLINOIS )
: ss.:
COUNTY OF COOK )
May 27, 1998
Then personally appeared the above-named Patricia Trlak, a
Vice President of U.S. Bank Trust National Association and
acknowledged the foregoing instrument to be her free act and deed
in her said capacity and the free act and deed of said corporation.
Before me,
/s/ P. Burrows
Notary Public
-24-
Exhibit 4(v)
THIS INSTRUMENT GRANTS A SECURITY INTEREST
BY A TRANSMITTING UTILITY
THIS INSTRUMENT CONTAINS AFTER-ACQUIRED PROPERTY PROVISIONS
MAINE PUBLIC SERVICE COMPANY
TO
U.S. BANK TRUST
NATIONAL ASSOCIATION
Trustee
NINETEENTH SUPPLEMENTAL INDENTURE
Dated as of May 1, 1998
Supplementing and Modifying Indenture of Mortgage and
Deed of Trust dated as of October 1, 1945
and
Relating to an Issue of Mortgage and
Collateral Trust Bonds, Series due 2008
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 NINETEENTH SUPPLEMENTAL INDENTURE (hereinafter called the
"Nineteenth Supplemental Indenture"), dated as of May 1, 1998, made
by MAINE PUBLIC SERVICE COMPANY, a Maine corporation (hereinafter
called the "Company"), party of the first part, and U.S. BANK TRUST
NATIONAL ASSOCIATION (formerly known as First Trust National
Association, as successor to Continental Bank, National Association
(formerly, Continental Illinois National Bank and Trust Company of
Chicago)), a national banking association duly organized and
existing under the laws of the United States of America, and having
its principal place of business in the City of Chicago, State of
Illinois (hereinafter called the "Trustee"), party of the second
part.
WHEREAS, the Company has heretofore executed and delivered to
the Trustee an Indenture of Mortgage and Deed of Trust, dated as of
October 1, 1945 (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 "First 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 an initial series of Bonds designated
as "First Mortgage and Collateral Trust Bonds, 2 7/8% Series due
1975" (herein sometimes called "Bonds of the 1975 Series"); and
WHEREAS, the Company has heretofore executed and delivered to
the Trustee a First Supplemental Indenture, dated as of September
1, 1950, pursuant to which the Company provided for the creation of
a second series of Bonds designated as "First Mortgage and
Collateral Trust Bonds, 3% Series due 1980" (herein sometimes
called "Bonds of the 1980 Series"), a Second Supplemental
Indenture, dated as of February 1, 1955, pursuant to which the
Company provided for the creation of a third series of Bonds
designated as "First Mortgage and Collateral Trust Bonds, 3.35%
Series due 1985" (herein sometimes called "Bonds of the 1985
Series"), a Third Supplemental Indenture, dated as of September 1,
1960, pursuant to which the Company provided for the creation of a
fourth series of Bonds designated as "First Mortgage and Collateral
Trust Bonds, 5 1/2% Series due 1990" (herein sometimes called
"Bonds of the 1990 Series"), a Fourth Supplemental Indenture, dated
as of January 1, 1965, pursuant to which the Company provided for
the creation of a fifth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 4 3/4% Series due 1995"
(herein sometimes called "Bonds of the 1995 Series"), a Fifth
Supplemental Indenture, dated as of May 1, 1968, pursuant to which
the Company provided for the creation of a sixth series of Bonds
designated as "First Mortgage and Collateral Trust Bonds, 7 1/8%
Series due 1998" (herein sometimes called "Bonds of the 1998
Series"), a Sixth Supplemental Indenture, dated as of March 1,
1973, pursuant to which the Company supplemented and modified the
Original Indenture and provided for the creation of a seventh
series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, 7.95% Series due 2003" (herein sometimes called "Bonds of
the 2003 Series"), a Seventh Supplemental Indenture, dated as of
September 1, 1975, pursuant to which the Company supplemented and
modified the Original Indenture and provided for the creation of an
eighth series of Bonds designated as "First Mortgage and Collateral
Trust Bonds, 10 5/8% Series due 1995" (herein sometimes called
"Bonds of the Second 1995 Series"), an Eighth Supplemental
Indenture, dated as of January 1, 1977, pursuant to which the
Company supplemented the Original Indenture, a Ninth Supplemental
Indenture, dated as of March 1, 1978, pursuant to which the Company
supplemented and modified the Original Indenture, a Tenth
Supplemental Indenture, dated as of October 1, 1979, pursuant to
which the Company supplemented the Original Indenture and provided
for the creation of a ninth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 10 1/4% Series due 2004"
(herein sometimes called "Bonds of the 2004 Series"), an Eleventh
Supplemental Indenture, dated as of January 15, 1983, pursuant to
which the Company supplemented the Original Indenture and provided
for the creation of a tenth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 13 7/8% Series due 1992"
(herein sometimes called "Bonds of the 1992 Series"), a Twelfth
Supplemental Indenture, dated as of July 1, 1984, pursuant to which
the Company supplemented the Original Indenture and provided for
the creation of an eleventh series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, 16.30% Series due 1989"
(herein sometimes called "Bonds of the 1989 Series"), a Thirteenth
Supplemental Indenture, dated as of July 1, 1984, pursuant to which
the Company supplemented the Original Indenture and provided for
the creation of a twelfth series of Bonds designated as "First
Mortgage and Collateral Trust Bonds, Floating Rate Series A due
1985" (herein sometimes called "Bonds of the Series A due 1985"),
a Fourteenth Supplemental Indenture, dated as of July 1, 1985,
pursuant to which the Company supplemented the Original Indenture
and provided for the creation of a thirteenth series of Bonds
designated as "First Mortgage and Collateral Trust Bonds, Floating
Rate Series B due 1986" (herein sometimes called "Bonds of the
Series B due 1986"), a Fifteenth Supplemental Indenture, dated as
of March 1, 1986, pursuant to which the Company supplemented the
Original Indenture and provided for the creation of a fourteenth
series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, 11% Series due 1996" (herein sometimes called "Bonds of the
1996 Series"), a Sixteenth Supplemental Indenture, dated as of
September 1, 1991, pursuant to which the Company supplemented the
Original Indenture and provided for the creation of a fifteenth
series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, 9.775% Series due 2011" (herein sometimes called "Bonds of
the 2011 Series"), a Seventeenth Supplemental Indenture, dated as
of April 1, 1997, pursuant to which the Company supplemented the
Original Indenture and provided for the creation of a sixteenth
series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, Series due 2005" (herein sometimes called "Bonds of the 2005
Series"), and an Eighteenth Supplemental Indenture, dated as of
April 1, 1998, pursuant to which the Company supplemented the
Original Indenture and provided for the creation of a seventeenth
series of Bonds designated as "First Mortgage and Collateral Trust
Bonds, Series due 1999" (herein sometimes called "Bonds of the 1999
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 First Mortgage and
Collateral Trust Bonds of series and in principal amounts as
follows:
Issued Outstanding
Bonds of the 1999 Series $2,000,000 $2,000,000
Bonds of the 2003 Series 2,500,000 1,900,000
Bonds of the 2005 Series 11,000,000 11,000,000
Bonds of the 2011 Series 15,000,000 15,000,000
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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 First Mortgage and Collateral Trust Bonds,
Series due 2008 (herein sometimes called the "Bonds of the 2008
Series"), and the Original Indenture provides that each series of
Bonds (except the Bonds of the 1975 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 Eighteenth 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 2008 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
Nineteenth Supplemental Indenture, a valid and binding mortgage and
deed of trust 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 Nineteenth Supplemental Indenture
and the issue of the Bonds of the 2008 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 Nineteenth Supplemental Indenture (the
Original Indenture, as supplemented by the First, Second, Third,
Fourth, Fifth, Eighth, Tenth, Eleventh, Twelfth, Thirteenth,
Fourteenth, Fifteenth and Sixteenth Supplemental Indentures, as
supplemented and modified by the Sixth, Seventh, Ninth,
Seventeenth and Eighteenth Supplemental Indentures and as
supplemented and modified by this Nineteenth 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
-3-
and its successors in the trust under the Original Indenture, as supplemented
and modified, as follows:
ARTICLE ONE
Schedule of Mortgaged Property.
SECTION 1.01. In order to further secure the payment of the
principal of, premium, if 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 Nineteenth 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 Nineteenth Supplemental Indenture and
by these presents does grant, bargain, sell, alien, remise,
release, convey, assign, transfer, mortgage, pledge, set over and
confirm unto U.S. Bank Trust National Association, as Trustee under
the Indenture, and to its assigns forever, all property, real,
personal or mixed, acquired since the execution and delivery of the
Eighteenth 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
No additional property.
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 apparatuses, 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.
-4-
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 reversions, 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,
-5-
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 VII 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
VII; and
(b) All property which prior to the execution and
delivery of this Nineteenth 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, as modified by the provisions of the
Sixth Supplemental Indenture, the Seventh Supplemental Indenture,
the Ninth Supplemental Indenture, the Seventeenth Supplemental
Indenture and the Eighteenth Supplemental Indenture and, with
respect to any property which the Company may hereafter acquire, to
all terms, conditions, agreements, covenants, exceptions
-6-
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 2008 Series and Certain
Provisions Relating Thereto
Section 2.01. Terms of the Bonds of the 2008 Series. There
shall be a series of Bonds, known as and entitled "First Mortgage
and Collateral Trust Bonds, Series due 2008" (herein referred to as
the "Bonds of the 2008 Series"), and the form thereof shall be
substantially as hereinafter set forth in Section 2.02.
The Bonds of the 2008 Series are issued to the Finance
Authority of Maine ("FAME") to secure the obligations of the
Company under the Loan Agreement by and between FAME and the
Company dated as of May 1, 1998 (together with any amendments,
modifications or supplements thereto, extensions, renewals,
deferrals, refunding or refinancing thereof or replacements or
successors therefor which may hereafter exist, the "Loan
Agreement"), with FAME's right, title and interest under said Loan
Agreement, the Bonds of the 2008 Series and certain other
collateral of the Company (except Shared Rights, as defined in said
Loan Agreement, which with respect to rights of enforcement may be
exercised by FAME and the FAME Trustee, as hereinafter defined,
jointly or severally, and with respect to rights of consent to the
modification of or waiver of compliance may be exercised by FAME
and the FAME Trustee, jointly but not severally, and Unassigned
Issuer's Rights, as defined in said Loan Agreement) being
concurrently with the execution and delivery of the Bonds of the 2008 Series
-7-
assigned without recourse to Peoples Heritage Bank, as
Trustee (the "FAME Trustee"), as security for $11,540,000 principal
amount of Taxable Electric Rate Stabilization Revenue Notes Series
1998A (Maine Public Service Company) (the "FAME Notes") as provided
for and issued under the Trust Indenture (the "FAME Indenture")
between FAME and the FAME Trustee, dated as of May 1, 1998. Under
and subject to the terms and conditions of the Loan Agreement, FAME
has agreed to make a Loan (as defined therein) to the Company
evidenced by a promissory note, the Loan Note (as defined therein),
with the obligations and liabilities (including, but not limited
to, obligations with respect to any fees, disbursements or other
expenses and indemnification) of the Company due and to become due
under the Loan Note or otherwise in respect of the Loan Agreement,
in each case, whether direct or indirect, joint or several,
absolute or contingent, liquidated or unliquidated, now or
hereafter existing, extended or renewed, deferred, refunded,
refinanced or restructured, and including all indebtedness of the
Company under any instrument now or hereafter evidencing any of the
foregoing, all being hereinafter called the "Loan Agreement
Obligations".
The aggregate principal amount of the Bonds of the 2008 Series
which may be authenticated and delivered and outstanding under this
Nineteenth Supplemental Indenture shall be limited to $4,000,000
except for duplicate Bonds, authenticated and delivered pursuant to
Section 2.12 of the Original Indenture. The definitive Bonds of
the 2008 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 the FAME Trustee.
The date of authentication on the original issuance of the
Bonds of the 2008 Series shall be the date of commencement of the
first interest period for such Bonds. All Bonds of the 2008 Series
shall mature June 1, 2008, and shall bear interest at the
applicable rate of interest as set forth in, and in accordance
with, the Loan Agreement until the payment of the principal
thereof. Both principal of and interest on the Bonds of the 2008
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 Chicago, Illinois, of the Trustee or, at the office of its
successor as Trustee, except that, in case of the redemption as a
whole at any time of Bonds of the 2008 Series then outstanding, the
Company may designate in the redemption notice other offices or
agencies at which, at the option of the registered holders, Bonds
of the 2008 Series may be surrendered for redemption and payment;
and in the case of interest on Bonds of the 2008 Series, at the
option of the registered holder, at the agency of the Company in
the Borough of Manhattan, City and State of New York, in each case
to the holder of record on the record date as hereinbelow defined.
Interest on the Bonds of the 2008 Series shall, unless otherwise
directed by the respective registered holders thereof, be paid by
checks payable to the order of the respective holders entitled
thereto, and mailed by the Trustee by first class mail, postage
prepaid, to such holders at their respective registered addresses
as shown on the Bond register for the Bonds of the 2008 Series.
The definitive Bonds of the 2008 Series may be issued in the
form of Bonds engraved, printed or lithographed on steel engraved
borders and the signature of the President, or a Vice President and
of the Secretary or an Assistant Secretary of the Company may be facsimile.
-8-
Bonds of the 2008 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.
Notwithstanding any provision in the Original Indenture to the
contrary, the person in whose name any Bond of the 2008 Series is
registered at the close of business on any record date (as
hereinbelow defined) with respect to any interest payment date
shall be entitled to receive the interest payable on such interest
payment date notwithstanding the cancellation of such Bond of the
2008 Series upon any transfer or exchange thereof (including any
exchange effected as an incident to a partial redemption thereof)
subsequent to the record date and prior to such interest payment
date, except that, if and to the extent that the Company shall
default in the payment of the interest due on such interest payment
date, then the registered holders of Bonds of the 2008 Series on
such record date shall have no further right to or claim in respect
of such defaulted interest as such registered holders on such
record date, and the persons entitled to receive payment of any
defaulted interest thereafter payable or paid on any Bonds of the
2008 Series shall be the registered holders of such Bonds of the
2008 Series on the record date for payment of such defaulted
interest. The term "record date" as used in this Section 2.01, and
in the form of the Bonds of the 2008 Series, with respect to any
interest payment date applicable to the Bonds of the 2008 Series,
shall mean the May 15 next preceding a June 1 interest payment date
or the November 15 next preceding a December 1 interest payment
date, as the case may be, or a special record date established for
defaulted interest as hereinafter provided.
In the case of failure by the Company to pay any interest when
due, the claim for such interest shall be deemed to have been
transferred by transfer of any Bond of the 2008 Series registered
on the Bond register, and the Company by not less than 10 days
written notice to bondholders may fix a subsequent record date, not
more than 15 days prior to the date fixed for the payment of such
interest, for determination of holders entitled to payment of such
interest. Such provision for establishment of a subsequent record
date, however, shall in no way affect the rights of bondholders or
of the Trustee consequent on any default.
Except as provided in this Section 2.01, every Bond of the
2008 Series shall be dated as provided in Section 2.05 of the
Original Indenture except that upon original issuance of the Bonds
of the 2008 Series, the Bonds of the 2008 Series shall be dated the
date of authentication. Notwithstanding any provision in the
Original Indenture to the contrary, so long as there is no existing
default in the payment of interest on the Bonds of the 2008 Series,
all Bonds of the 2008 Series authenticated by the Trustee between
the record date for any interest payment date and such interest
payment date shall be dated such interest payment date and shall
bear interest from such interest payment date.
As permitted by the provisions of Section 2.10 of the Original Indenture
and upon payment at the option of the Company of a sum sufficient to reimburse
it for any stamp tax or other governmental charge as provided in Section 2.11
of the Original Indenture, Bonds of the
-9-
2008 Series may be exchanged for other Bonds of the 2008 Series of different
authorized denominations of like aggregate principal amount. Notwithstanding
the provisions of Section 2.11 or the last sentence of the first paragraph of
Section 2.12 of the Original Indenture, no further sum, other than the sum
sufficient to reimburse the Company for any stamp taxes or other governmental
charges, shall be required to be paid upon any exchange or replacement of Bonds
of the 2008 Series or upon any transfer thereof.
The Bonds of the 2008 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 the FAME Trustee if
and to the extent that the FAME Trustee shall have assigned its
rights under the Loan Agreement, any such transfer to be made at
the principal corporate trust office of the Trustee in the City of
Chicago, Illinois, upon surrender and cancellation of such Bonds of
the 2008 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 2008 Series or by his duly authorized
attorney, and thereupon a new Bond of the 2008 Series, for a like
principal amount, will be issued to the successor of the FAME
Trustee, 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 2008 Series.
Notwithstanding any provision in the Original Indenture to the
contrary, neither the Company nor the Trustee shall be required to
make transfers or exchanges of Bonds of the 2008 Series for a
period of ten days next preceding any designation of the Bonds of
the 2008 Series to be redeemed and neither the Company nor the
Trustee shall be required to make transfers or exchanges of any
bonds designated in whole for redemption or that part of any bond
designated in part for redemption.
Section 2.02. Form of Bonds of the 2008 Series. The text of
the Bonds of the 2008 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 2008 SERIES]
No. [ ] $_____________
MAINE PUBLIC SERVICE COMPANY
First Mortgage and Collateral Trust Bond,
Series due 2008
Due June 1, 2008
MAINE PUBLIC SERVICE COMPANY, a Maine corporation (hereinafter
sometimes called the "Company"), for value received, hereby
promises to pay to
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or registered assigns, on June 1, 2008, the sum of
Dollars (the "Stated Principal Amount") or, if less,
the Effective Principal Amount (as hereinafter defined) on such
date, and to pay to the registered owner hereof interest on the
Stated Principal Amount or, if less, on the Effective Principal
Amount from the date hereof at the applicable rate of interest as
set forth in, and in accordance with, the Loan Agreement (as
hereinafter defined) until the payment of the principal thereof.
The Bonds of the 2008 Series, including this bond, are issued
to secure the obligations of the Company under the Loan Agreement
by and between the Finance Authority of Maine ("FAME") and the
Company dated as of May 1, 1998 (together with any amendments,
modifications or supplements thereto, extensions, renewals,
deferrals, refunding or refinancing thereof or replacements or
successors therefor which may hereafter exist, the "Loan
Agreement"), with FAME's right, title and interest under said Loan
Agreement, the Bonds of the 2008 Series and certain other
collateral of the Company (except Shared Rights, as defined in said
Loan Agreement, which with respect to rights of enforcement may be
exercised by FAME and the FAME Trustee, as hereinafter defined,
jointly or severally, and with respect to rights of consent to the
modification of or waiver of compliance may be exercised by FAME
and the FAME Trustee, jointly but not severally, and Unassigned
Issuer's Rights, as defined in said Loan Agreement) being
concurrently with the execution and delivery of the Bonds of the
2008 Series assigned without recourse to Peoples Heritage Bank, as
Trustee (the "FAME Trustee"), as security for $11,540,000 principal
amount of Taxable Electric Rate Stabilization Revenue Notes Series
1998A (Maine Public Service Company) (the "FAME Notes") as provided
for and issued under the Trust Indenture (the "FAME Indenture")
between FAME and the FAME Trustee, dated as of May 1, 1998. Under
and subject to the terms and conditions of the Loan Agreement, FAME
has agreed to make a Loan (as defined therein) to the Company
evidenced by a promissory note, the Loan Note (as defined therein),
with the obligations and liabilities (including, but not limited
to, obligations with respect to any fees, disbursements or other
expenses and indemnification) of the Company due and to become due
under the Loan Note or otherwise in respect of the Loan Agreement,
in each case, whether direct or indirect, joint or several,
absolute or contingent, liquidated or unliquidated, now or
hereafter existing, extended or renewed, deferred, refunded,
refinanced or restructured, and including all indebtedness of the
Company under any instrument now or hereafter evidencing any of the
foregoing, all being hereinafter called the "Loan Agreement
Obligations". The "Effective Principal Amount" of this bond as of
the time of any determination is an amount equal to the Loan
Agreement Obligations outstanding and unpaid at such time
multiplied by a fraction, the numerator of which is 4 and the
denominator of which is 11.54, such product in turn to be
multiplied by a fraction, the numerator of which is the Stated
Principal Amount and the denominator of which is $4,000,000.
The obligation of the Company to make any payment of interest
on the Bonds of the 2008 Series, when such interest shall be due
and payable (including, but not limited to, June 1, 2008), shall be
deemed to be, and shall be, satisfied and discharged if the Company
shall have paid all interest under the Loan Agreement then due and
payable. The obligation of the Company to make payments with
respect to the principal of the Bonds of the 2008 Series at any
time shall be deemed to be, and shall be, satisfied and discharged
if, at any time that such
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payment of principal shall be due (including, but not limited to, June 1, 2008),
the Company shall have paid all amounts then due pursuant to Sections 4.2 and
4.3 of the Loan Agreement or otherwise due with respect to Loan Agreement
Obligations.
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 Chicago, Illinois, of
the Trustee under the Indenture mentioned on the reverse hereof
except that in case of the redemption as a whole at any time of the
bonds of this series then outstanding, the Company may designate in
the redemption notice other offices or agencies at which, at the
option of the registered holder, this bond may be surrendered for
redemption and payment. Interest on this bond will be payable at
the Corporate Trust Division office in the City of Chicago,
Illinois, of the Trustee, or, at the option of the holder hereof,
at the agency of the Company in the Borough of Manhattan, City and
State of New York; 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 by 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 2008 SERIES]
This bond constitutes the entire series designated as Bonds of
the 2008 Series, of an authorized issue of bonds of the Company,
known as First Mortgage and Collateral Trust Bonds, issued under
and equally secured (except in so far as any sinking fund,
replacement fund or
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other fund established in accordance with the provisions of the Indenture
hereinafter mentioned may afford additional security for the bonds of any
specific series) by an Indenture of Mortgage and Deed of Trust dated as of
October 1, 1945, duly executed and delivered by the Company to U.S. Bank Trust
National Association, (formerly known as First Trust National Association, as
successor to Continental Bank, National Association (formerly, Continental
Illinois National Bank and Trust Company of Chicago)), as Trustee, to which
Indenture of Mortgage and Deed of Trust as supplemented and modified by
indentures supplemental thereto, including a Nineteenth Supplemental Indenture
dated as of May 1, 1998, duly executed by the Company to said Trustee and all
further 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 hereof on the date fixed for
redemption in the manner provided for in the Indenture. Upon the
occurrence of certain Events of Default specified in Section 9.03
of the FAME Indenture (including, but not limited to the failure to
pay when due the principal of, and interest on, any FAME Note), the
Trustee may (and upon the written request of the Holders of not
less than 25% in the aggregate amount of FAME Notes then
outstanding, shall) declare the principal amount of all FAME Notes
then outstanding, together with the interest accrued thereon, to be
due and payable immediately. Upon any such declaration of
acceleration under the FAME Indenture, the FAME Trustee may
immediately exercise its rights (i) under the Loan Agreement to
declare all payments thereunder to be immediately due and payable,
and (ii) to demand redemption of this bond by the Company. In such
event, this bond shall be redeemed by the Company at the Stated
Principal Amount hereof or, if less, the Effective Principal Amount
hereof on the date fixed for redemption.
If this bond (or any portion thereof (One Dollar or a multiple
thereof)) 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.
Except as may be otherwise provided in any agreement entered
into pursuant to the provisions of said Nineteenth Supplemental
Indenture, in the event of the selection for redemption of a
portion only of the principal of this bond, payment of the
redemption price will be made only (a) upon presentation of this
bond for notation hereon of such payment of the portion of the
principal of this bond so called for redemption, or (b) upon
surrender of this bond in exchange for a bond or bonds of
authorized denominations of the same series, for the unredeemed
balance of the principal amount of this bond.
The Indenture contains provisions permitting the Company and
the Trustee, with the consent of the holders of the not less than
seventy-five percent in principal amount of the bonds
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(exclusive of bonds disqualified by reason of the Company's interest therein)
at the time outstanding, including, if more than one series of bonds
shall be at the time outstanding, not less than sixty percent in
principal amount of each series affected, to effect, by an
indenture supplemental to the Indenture, modifications or
alterations of the Indenture and of the rights and obligations of
the Company and of the holders of the bonds; provided, however,
that no such modification or alteration shall be made without the
written approval or consent of the registered holder hereof which
will (a) extend the maturity of this bond or reduce the rate or
extend the time of payment of interest hereon or reduce the amount
of the principal hereof or (b) permit the creation of any lien, not
otherwise permitted, prior to or on a parity with the lien of the
Indenture, or (c) reduce the percentage of the principal amount of
the bonds upon the approval or consent of the holders of which
modifications or alterations may be made as aforesaid.
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 the FAME Trustee if and to the extent
that the FAME Trustee shall have assigned its rights under the Loan
Agreement, any such transfer to be made at the principal corporate
trust office of the Trustee in the City of Chicago, Illinois, or,
at the option of such registered holder hereof, at the agency of
the Company in the Borough of Manhattan, City and State of New
York, upon surrender of this bond for cancellation and upon
payment, if the Company shall so require, of the stamp taxes and
other governmental charges provided for in said Nineteenth
Supplemental Indenture, 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 the FAME
Trustee in exchange therefor, as provided in the Indenture.
The registered holder of this bond at his option may surrender
the same for cancellation at said office of the Trustee and receive
in exchange therefor the same aggregate principal amount of
registered bonds of the same series but of other authorized
denominations upon payment, if the Company shall so require, of the
stamp taxes and other governmental charges provided for in said
Nineteenth Supplemental Indenture and subject to the terms and
conditions therein set forth.
Neither the Company nor the Trustee shall be required to make
transfers or exchanges of bonds of this series for a period of ten
days next preceding any designation of bonds of said series to be
redeemed, and neither the Company nor the Trustee shall be required to make
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transfers or exchanges of any bonds designated in whole for
redemption or that part of any bond designated in part for
redemption. Subject to the provisions of said Nineteenth
Supplemental Indenture, if this bond is surrendered for any
transfer or exchange between the record date for any interest
payment date and such interest payment date, the new bond will be
dated such interest payment date.
The Indenture provides that in the event of any default in
payment of the interest due on any interest payment date, such
interest shall not be payable to the holder of the bond on the
original record date but shall be paid to the registered holder of
such bond on the subsequent record date established for payment of
such defaulted interest.
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 these
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 2008 SERIES]
This is one of the bonds, of the series designated therein,
described in the within mentioned Indenture.
U.S. BANK TRUST NATIONAL
ASSOCIATION,
As Trustee,
By:
Authorized Officer
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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 2008 Series, when such interest shall be due and
payable (including, but not limited to, June 1, 2008), shall be
deemed to be, and shall be, satisfied and discharged if the Company
shall have paid all interest under the Loan Agreement then due and
payable. The obligation of the Company to make payments with
respect to the principal of Bonds of the 2008 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
(including, but not limited to, June 1, 2008), the Company shall
have paid the FAME Trustee all amounts then due pursuant to
Sections 4.2 and 4.3 of the Loan Agreement or otherwise due with
respect to the Loan Agreement Obligations. 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 2008 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 Loan Agreement
Obligations shall have been satisfied, all of the Bonds of the 2008
Series shall be surrendered by the FAME Trustee to the Trustee for
cancellation, and upon such surrender shall be deemed fully paid.
Section 2.04. Redemption Provisions for the Bonds of the 2008
Series. Subject to the terms of the Loan Agreement applicable to
prepayment of the Loan Note, the Bonds of the 2008 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 an amount
equal to the Stated Principal Amount thereof or, if less, the
Effective Principal Amount thereof including interest accrued
thereon to the redemption date.
Upon the occurrence of certain Events of Default specified in
Section 9.03 of the FAME Indenture (including, but not limited to,
the failure to pay when due the principal of, and interest on, any
FAME Note), the Trustee may (and upon the written request of the
Holders of not less than 25% in the aggregate amount of FAME Notes
then outstanding, shall) declare the principal amount of all FAME
Notes then outstanding, together with the interest accrued thereon,
to be due and payable immediately. Upon any such declaration of
acceleration under the FAME Indenture, the FAME Trustee may
immediately exercise its rights (i) under the Loan Agreement to
declare all payments thereunder to be immediately due and payable,
and (ii) to demand redemption of the Bonds of the 2008 Series by
the Company. In such event, all Bonds of the 2008 Series then
outstanding shall be redeemed by the Company, on the date such FAME
Notes shall have become immediately due and payable, at the Stated
Principal Amount or, if less, the Effective Principal Amount
thereof including interest accrued thereon to the redemption date.
The Trustee may conclusively presume that no redemption of
Bonds of the 2008 Series is required pursuant to this Section 2.04
unless and until the Trustee shall have received a written notice
from the FAME Trustee as described in Section 12.01(k) of the
Indenture.
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No notice of redemption pursuant to Section 10.02 of the
Indenture need be given if the holders of all Bonds of the 2008
Series called for redemption waive notice thereof in writing and
such waiver is filed with the Trustee.
SECTION 2.05. Bondholders' List. Notwithstanding the
provisions of Section 11.02(B) of the Original Indenture, any one
of the holders of the Bonds of the 2008 Series shall be entitled to
make application to the Trustee for a Bondholders' list as provided
for in Section 11.02.
SECTION 2.06. Mutilated, Lost or Destroyed Bonds.
Notwithstanding the provisions of Section 2.12 of the Original
Indenture, for so long as any holder of Bonds of the 2008 Series
shall be an institutional holder, an unsecured indemnity provided
by such holder shall be deemed acceptable for purposes of
requesting a replacement bond for a mutilated, lost or destroyed
Bond of the 2008 Series.
Section 2.07 Duration of Effectiveness of Article Two. This
Article shall be of force and effect only so long as any Bonds of
the 2008 Series are outstanding.
ARTICLE THREE
Modification of the Indenture
Section 3.01. Section 12.01 of the Indenture is hereby amended
by adding new clause (k) thereto which reads as follows:
"(k) so long as any of the Bonds of the 2008 Series are
outstanding, upon receipt by the Trustees of a notice
from the holder of the Bonds of the 2008 Series that an
event of default under the Loan Agreement has occurred
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 2008 Series are outstanding.
ARTICLE FOUR
Authentication and Delivery of Bonds of the 2008 Series
Section 4.01. Upon the execution and delivery of this
Nineteenth Supplemental Indenture, Bonds of the 2008 Series in the
aggregate amount of Four Million Dollars ($4,000,000) 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
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upon the written order of the Company. Additional Bonds of the 2008
Series may be executed, authenticated and delivered from time to
time as permitted by the provisions of Article Five of the Original
Indenture.
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 Nineteenth 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 Nineteenth
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 Nineteenth 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 Nineteenth 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 Nineteenth 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
Nineteenth 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.
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Section 5.06. The titles of Articles and any wording on the
cover of this Nineteenth Supplemental Indenture are inserted for
convenience only.
Section 5.07. All the covenants, stipulations, promises and
agreements in this Nineteenth 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 Nineteenth Supplemental Indenture
is dated for convenience and for the purpose of reference as of May
1, 1998, 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 Nineteenth 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.
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IN WITNESS WHEREOF, MAINE PUBLIC SERVICE COMPANY has caused
this Nineteenth 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
U.S. BANK TRUST NATIONAL ASSOCIATION in token of its acceptance of
the trust hereby created has caused this Nineteenth 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, 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/ Kurt A. Tornquist
Name: Kurt A. Tornquist
Title: Assistant Secretary
Signed, sealed and delivered
by MAINE PUBLIC SERVICE COMPANY
in the presence of:
/s/ Marilyn L. Bouchard
Marilyn L. Bouchard
/s/ Alice E. Shepard
Alice E. Shepard
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U.S. BANK TRUST NATIONAL
ASSOCIATION
/s/ Patricia M. Trlak
Name:Patricia M. Trlak
Title:Vice President
CORPORATE SEAL
Attest:
/s/ Larry Kusch
Name: Larry Kusch
Title: Assistant Secretary
Signed, sealed and delivered
by U.S. BANK TRUST NATIONAL
ASSOCIATION in the presence of:
/s/ Harry H. Hall
Name: Harry H. Hall
Title: Vice President
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STATE OF MAINE )
: ss.:
COUNTY OF AROOSTOOK )
May 26, 1998
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
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STATE OF ILLINOIS )
: ss.:
COUNTY OF COOK )
May 27, 1998
Then personally appeared the above-named Patricia Trlak, a
Vice President of U.S. Bank Trust National Association and
acknowledged the foregoing instrument to be her free act and deed
in her said capacity and the free act and deed of said corporation.
Before me,
/s/ P. Burrows
Notary Public
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Exhibit 10(v)
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
FOURTH SUPPLEMENTAL INDENTURE
Dated as of May 1, 1998
Supplementing and Modifying 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 2008
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 FOURTH SUPPLEMENTAL INDENTURE (hereinafter called the
"Fourth Supplemental Indenture"), dated as of May 1, 1998, 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, the Company has heretofore executed and delivered to
the Trustee a Third Supplemental Indenture, dated as of June 1,
1996, pursuant to which the Company supplemented and modified the
Original Indenture, as supplemented and modified, and provided for
the creation of a sixth series of Bonds designated as "Second
Mortgage and Collateral Trust Bonds, Series due 2002" (herein
sometimes called "Bonds of the 2002 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 $5,000,000
Bonds of the 2002 Series 15,875,000 15,875,000
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 2008 (herein sometimes called the "Bonds of the 2008
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 Third 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 2008 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
Fourth 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 Fourth Supplemental Indenture and
the issue of the Bonds of the 2008 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 Fourth Supplemental Indenture (the
Original Indenture, as supplemented and modified by the First
Supplemental Indenture and the Third Supplemental Indenture, and
supplemented by the Second Supplemental Indenture and as
supplemented and modified by this Fourth 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
-2-
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 to further secure the payment of the
principal of, premium, if 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 Fourth 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 Fourth 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 Third
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
A certain piece or parcel of land situated in the Westerly
part of Original Lot No. One Hundred Thirty (#130) in Township 18,
Range 5, W.E.L.S., now Madawaska, in the County of Aroostook and
State of Maine, being more particularly bound and described as
follows:
Commencing at the East corner of the parcel conveyed to
Maine Public Service Company by deed recorded in the Northern
Aroostook Registry of Deeds in Volume 330, Page 566, said point
being also the North corner of Lot No. Thirty-One (#31) on
Madawaska town map sheet number Seven (7) as prepared by J.W.
Sewall Co.; thence Northwesterly along the Northeast property line
of the said Maine Public Service Company parcel to the North corner
of said MPS parcel, a distance of One Hundred Forty-nine and Seven
Tenths (149.7) feet; thence
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Northeasterly on a continuation of the Northwest property line of said MPS
parcel, to the Southwest property line of the parcel conveyed to the Inhabitants
of the Town of Madawaska by Fraser Paper, Ltd, a distance of Fifty (50) feet,
more or less, said property line being also the boundary between
the parcel owned by Eldon J. Cyr and the parcel owned by the
Inhabitants of Madawaska, thence Southeasterly along the Southwest
property line of the parcel conveyed to the Inhabitants of the Town
of Madawaska to the South corner of the parcel conveyed to the
Inhabitants of Madawaska, said corner being also the West corner of
Lot Six (6) on Madawaska town map sheet Seven (7) as prepared by J.
W. Sewall Co., a distance of One Hundred Fifty (150) feet, more or
less, thence Southwesterly, a distance of Fifty (50) feet to the
point of beginning.
Being part of the premises conveyed to Eldon J. Cyr by
Warranty Deed of Fraser Paper, Limited, dated May 6, 1994, recorded
in the Northern Aroostook Registry of Deeds in Volume 948, Page 98.
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:
Harold & Theodore Sherman 8/08/97 3021 044 Houlton
Edith A. Dwyer 8/08/97 3021 040 Houlton
Norman Grant III 9/15/97 3060 152 Houlton
Dale Hosford 10/28/97 3075 330 Houlton
Edith A. Dwyer 12/18/97 3090 319 Houlton
RIGHT-OF-WAY, FORT KENT WASTE WATER TREATMENT PLANT, SO CALLED
A 34,500 volt transmission line in Aroostook County, Maine
owned and operated by Maine Public Service Company from Route 161
in Ashland, Maine south .28 miles to the Fort Kent Waste Water
Treatment Plant, said Maine Public Service Company line being constructed
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for the most part on a right-of-way conveyed to Maine Public Service Company by
the following deed:
Grantor Date Vol. Page Registry at:
Fort Kent Utility District 10/17/96 1048 276 Fort Kent
RIGHT-OF-WAY, ROUTE 11 REBUILD, SO CALLED
A 34,500 volt transmission line Aroostook County, Maine owned
and operated by Maine Public Service Company from junction of Rt.
163 & Rt. 11 in Ashland, Maine and southerly along Rt. 11, a
distance of approximately 2.05 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:
Matt Walton 2/04/97 2985 322 Houlton
Mark D. Rafford, Sr. 2/04/97 2985 320 Houlton
Laura & Bernard Howes, Jr. 2/04/97 2985 317 Houlton
Kevin & Barbara Robinson 2/04/97 2985 315 Houlton
Melvin P. Graham 2/04/97 2985 313 Houlton
Milton & Dawn Clark 2/04/97 2985 311 Houlton
Chester B. & Katherine B. Rafford 2/04/97 2985 309 Houlton
Sherman L. & Charlotte O. Weaver 2/04/97 2985 297 Houlton
Beatrice Weaver 2/04/97 2985 299 Houlton
Dwight & Candace D. Junkins 2/04/97 2985 301 Houlton
John Beaulier 2/04/97 2985 303 Houlton
Clifford G. & Thelma A. White 2/04/97 2985 305 Houlton
Julie Belanger & Althea Holmes 2/04/97 2985 307 Houlton
Glori Coty & Barry Baranowski 2/04/97 2985 291 Houlton
Artimas & Rosemary M. Coffin 2/04/97 2985 295 Houlton
Robert & Bonnie Bowring 2/04/97 2985 293 Houlton
Hazen Stevens 4/03/97 2998 109 Houlton
Hazen Stevens 5/22/97 3016 154 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.
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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 apparatuses, 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 reversions, remainder and remainders, and the rents,
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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 Fourth 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.
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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 and
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 2008 Series and Certain
Provisions Relating Thereto
Section 2.01. Terms of the Bonds of the 2008 Series. There
shall be a series of Bonds, known as and entitled "Second Mortgage
and Collateral Trust Bonds, Series Due 2008" (herein referred to as
the "Bonds of the 2008 Series"), and the form thereof shall be
substantially as hereinafter set forth in Section 2.02.
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The Bonds of the 2008 Series shall be issued to the Finance
Authority of Maine ("FAME") to secure the obligations of the
Company under the Loan Agreement by and between FAME and the
Company dated as of May 1, 1998 (together with any amendments,
modifications or supplements thereto, extensions, renewals,
deferrals, refunding or refinancing thereof or replacements or
successors therefor which may hereafter exist, the "Loan
Agreement"), with FAME's right, title and interest under said Loan
Agreement, the Bonds of the 2008 Series and certain other
collateral of the Company (except Shared Rights, as defined in said
Loan Agreement, which with respect to rights of enforcement may be
exercised by FAME and the FAME Trustee, as hereinafter defined,
jointly or severally, and with respect to rights of consent to the
modification of or waiver of compliance may be exercised by FAME
and the FAME Trustee, jointly but not severally, and Unassigned
Issuer's Rights, as defined in said Loan Agreement) being
concurrently with the execution and delivery of the Bonds of the
2008 Series assigned without recourse to Peoples Heritage Bank, as
Trustee (the "FAME Trustee"), as security for $11,540,000 principal
amount of Taxable Electric Rate Stabilization Revenue Notes Series
1998A (Maine Public Service Company) (the "FAME Notes") as provided
for and issued under the Trust Indenture (the "FAME Indenture")
between FAME and the FAME Trustee, dated as of May 1, 1998. Under
and subject to the terms and conditions of the Loan Agreement, FAME
has agreed to make a Loan (as defined therein) to the Company
evidenced by a promissory note, the Loan Note (as defined therein),
with the obligations and liabilities (including, but not limited
to, obligations with respect to any fees, disbursements or other
expenses and indemnification) of the Company due and to become due
under the Loan Note or otherwise in respect of the Loan Agreement,
in each case, whether direct or indirect, joint or several,
absolute or contingent, liquidated or unliquidated, now or
hereafter existing, extended or renewed, deferred, refunded,
refinanced or restructured, and including all indebtedness of the
Company under any instrument now or hereafter evidencing any of the
foregoing, all being hereinafter called the "Loan Agreement
Obligations".
The aggregate principal amount of the Bonds of the 2008 Series
which may be authenticated and delivered and outstanding under this
Fourth Supplemental Indenture shall be limited to $7,540,000 except
for duplicate Bonds, authenticated and delivered pursuant to
Section 2.12 of the Original Indenture. The definitive Bonds of
the 2008 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 the FAME Trustee.
The date of authentication on the original issuance of the
Bonds of the 2008 Series shall be the date of commencement of the
first interest period for such Bonds. All Bonds of the 2008 Series
shall mature June 1, 2008, and shall bear interest at the
applicable rate of interest as set forth in, and in accordance
with, the Loan Agreement until the payment of the principal
thereof. Both principal of and interest on the Bonds of the 2008
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. Interest on the Bonds of the 2008 Series
shall, unless otherwise directed by the respective registered
holders thereof, be paid by checks payable to the order of the
respective holders entitled thereto, and mailed by the Trustee
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by first class mail, postage prepaid, to such holders at their
respective registered addresses as shown on the Bond register for
the Bonds of the 2008 Series.
The definitive Bonds of the 2008 Series may be issued in the
form of Bonds engraved, printed or lithographed on steel engraved
borders and the signature of the President, or a Vice President and
of the Secretary or an Assistant Secretary of the Company may be
facsimile. Bonds of the 2008 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.
Notwithstanding any provision in the Original Indenture to the
contrary, the person in whose name any Bond of the 2008 Series is
registered at the close of business on any record date (as
hereinbelow defined) with respect to any interest payment date
shall be entitled to receive the interest payable on such interest
payment date notwithstanding the cancellation of such Bond of the
2008 Series upon any transfer or exchange thereof (including any
exchange effected as an incident to a partial redemption thereof)
subsequent to the record date and prior to such interest payment
date, except that, if and to the extent that the Company shall
default in the payment of the interest due on such interest payment
date, then the registered holders of Bonds of the 2008 Series on
such record date shall have no further right to or claim in respect
of such defaulted interest as such registered holders on such
record date, and the persons entitled to receive payment of any
defaulted interest thereafter payable or paid on any Bonds of the
2008 Series shall be the registered holders of such Bonds of the
2008 Series on the record date for payment of such defaulted
interest. The term "record date" as used in this Section 2.01, and
in the form of the Bonds of the 2008 Series, with respect to any
interest payment date applicable to the Bonds of the 2008 Series,
shall mean the May 15 next preceding a June 1 interest payment date
or the November 15 next preceding a December 1 interest payment
date, as the case may be, or a special record date established for
defaulted interest as hereinafter provided.
In the case of failure by the Company to pay any interest when
due, the claim for such interest shall be deemed to have been
transferred by transfer of any Bond of the 2008 Series registered
on the Bond register, and the Company by not less than 10 days
written notice to bondholders may fix a subsequent record date, not
more than 15 days prior to the date fixed for the payment of such
interest, for determination of holders entitled to payment of such
interest. Such provision for establishment of a subsequent record
date, however, shall in no way affect the rights of bondholders or
of the Trustee consequent on any default.
Except as provided in this Section 2.01, every Bond of the
2008 Series shall be dated as provided in Section 2.05 of the
Original Indenture except that upon original issuance of the Bonds
of the 2008 Series, the Bonds of the 2008 Series shall be dated the
date of authentication. Notwithstanding any provision in the
Original Indenture to the contrary, so long as there is no existing
default in the payment of interest on the Bonds of the 2008 Series,
all Bonds of the 2008 Series authenticated by the Trustee between
the record date for any interest payment date and
-10-
such interest payment date shall be dated such interest payment date and shall
bear interest from such interest payment date.
As permitted by the provisions of Section 2.10 of the Original
Indenture and upon payment at the option of the Company of a sum
sufficient to reimburse it for any stamp tax or other governmental
charge as provided in Section 2.11 of the Original Indenture, Bonds
of the 2008 Series may be exchanged for other Bonds of the 2008
Series of different authorized denominations of like aggregate
principal amount. Notwithstanding the provisions of Section 2.11
or the last sentence of the first paragraph of Section 2.12 of the
Original Indenture, no further sum, other than the sum sufficient
to reimburse the Company for any stamp taxes or other governmental
charges, shall be required to be paid upon any exchange or
replacement of Bonds of the 2008 Series or upon any transfer
thereof.
The Bonds of the 2008 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 the FAME Trustee if
and to the extent that the FAME Trustee shall have assigned its
rights under the Loan 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 2008 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 2008 Series or by his duly authorized
attorney, and thereupon a new Bond of the 2008 Series, for a like
principal amount, will be issued to the successor or assignee of
the FAME Trustee, 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 2008 Series.
Notwithstanding any provision in the Original Indenture to the
contrary, neither the Company nor the Trustee shall be required to
make transfers or exchanges of Bonds of the 2008 Series for a
period of ten days next preceding any designation of the Bonds of
the 2008 Series to be redeemed and neither the Company nor the
Trustee shall be required to make transfers or exchanges of any
bonds designated in whole for redemption or that part of any bond
designated in part for redemption.
Section 2.02. Form of Bonds of the 2008 Series. The text of
the Bonds of the 2008 Series and the Trustee's authentication
certificate to be executed on the Bonds of said series, shall be in
substantially the following forms, respectively.
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[FORM OF FACE OF BOND OF THE 2008 SERIES]
No. [ ] $_____________
MAINE PUBLIC SERVICE COMPANY
Second Mortgage and Collateral Trust Bond,
Series due 2008
Due June 1, 2008
MAINE PUBLIC SERVICE COMPANY, a Maine corporation (hereinafter sometimes
called the "Company"), for value received, hereby promises to pay to or
registered assigns, on June 1, 2008, the sum of ________________ Dollars (the
"Stated Principal Amount") or, if less, the Effective Principal Amount (as
hereinafter defined) on such date, and to pay to the registered owner hereof
interest on the Stated Principal Amount or, if less, on the Effective Principal
Amount from the date hereof at the applicable rate of interest as set forth in,
and in accordance with, the Loan Agreement (as hereinafter defined) until the
payment of the principal thereof.
The Bonds of the 2008 Series, including this bond, are issued
to secure the obligations of the Company under the Loan Agreement
by and between the Finance Authority of Maine ("FAME") and the
Company dated as of May 1, 1998 (together with any amendments,
modifications or supplements thereto, extensions, renewals,
deferrals, refunding or refinancing thereof or replacements or
successors therefor which may hereafter exist, the "Loan
Agreement"), with FAME's right, title and interest under said Loan
Agreement, the Bonds of the 2008 Series and certain other
collateral of the Company (except Shared Rights, as defined in said
Loan Agreement, which with respect to rights of enforcement may be
exercised by FAME and the FAME Trustee, as hereinafter defined,
jointly or severally, and with respect to rights of consent to the
modification of or waiver of compliance may be exercised by FAME
and the FAME Trustee, jointly but not severally, and Unassigned
Issuer's Rights, as defined in said Loan Agreement) being
concurrently with the execution and delivery of the Bonds of the
2008 Series assigned without recourse to Peoples Heritage Bank, as
Trustee (the "FAME Trustee"), as security for $11,540,000 principal
amount of Taxable Electric Rate Stabilization Revenue Notes Series
1998A (Maine Public Service Company) (the "FAME Notes") as provided
for and issued under the Trust Indenture (the "FAME Indenture")
between FAME and the FAME Trustee, dated as of May 1, 1998. Under
and subject to the terms and conditions of the Loan Agreement, FAME
has agreed to make a Loan (as defined therein) to the Company
evidenced by a promissory note, the Loan Note (as defined therein),
with the obligations and liabilities (including, but not limited
to, obligations with respect to any fees, disbursements or other
expenses and indemnification) of the Company due and to become due
under the Loan Note or otherwise in respect of the Loan Agreement,
in each case, whether direct or indirect, joint or several, absolute or
contingent, liquidated or unliquidated, now or hereafter existing, extended
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or renewed, deferred, refunded, refinanced or restructured, and including all
indebtedness of the Company under any instrument now or hereafter evidencing any
of the foregoing, all being hereinafter called the "Loan Agreement Obligations".
The "Effective Principal Amount" of this bond as of the time of any
determination is an amount equal to the Loan Agreement Obligations outstanding
and unpaid at such time multiplied by a fraction, the numerator of which is 7.54
and the denominator of which is 11.54, such product in turn to be multiplied by
a fraction, the numerator of which is the Stated Principal Amount and the
denominator of which is $7,540,000.
The obligation of the Company to make any payment of interest
on the Bonds of the 2008 Series, when such interest shall be due
and payable (including, but not limited to, June 1, 2008), shall be
deemed to be, and shall be, satisfied and discharged if the Company
shall have paid all interest under the Loan Agreement then due and
payable. The obligation of the Company to make payments with
respect to the principal of the Bonds of the 2008 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
(including, but not limited to, June 1, 2008), the Company shall
have paid for all amounts then due pursuant to Sections 4.2 and 4.3
of the Loan Agreement or otherwise due with respect to the Loan
Agreement Obligations.
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
except that in case of the redemption as a whole at any time of the
bonds of this series then outstanding, the Company may designate in
the redemption notice other offices or agencies at which, at the
option of the registered holder, this bond may be surrendered for
redemption and payment. 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 by its President or one of its Vice
Presidents and
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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 2008 SERIES]
This bond constitutes the entire series designated as Bonds of
the 2008 Series, of an authorized issue of bonds of the Company,
known as Second Mortgage and Collateral Trust Bonds, issued under
and equally secured (except in so far as any sinking fund,
replacement fund or other fund established in accordance with the
provisions of the Indenture hereinafter mentioned may afford
additional security for the bonds of any specific series) 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 Fourth Supplemental
Indenture dated as of May 1, 1998, duly executed by the Company to
said Trustee and all further 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 hereof in the manner provided
for in the Indenture. Upon the occurrence of certain Events of
Default specified in Section 9.03 of the FAME Indenture (including,
but not limited to, the failure to pay when due the principal of,
and interest on, any FAME Note), the Trustee may (and upon the
written request of the Holders of not less than 25% in the
aggregate amount of FAME Notes then outstanding, shall) declare the
principal amount of all FAME Notes then outstanding, together with
the interest accrued thereon, to be due and payable immediately.
Upon any such declaration of acceleration under the FAME Indenture,
the FAME Trustee may immediately exercise its rights (i) under the
Loan Agreement to declare all payments thereunder to be immediately
due and payable, and (ii) to demand redemption of this bond by the
Company. In such event, this bond shall be redeemed by the Company
at the Stated Principal Amount hereof plus unpaid interest accrued
to the date of redemption.
-14-
If this bond (or any portion thereof (One Dollar or a multiple thereof))
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.
Except as may be otherwise provided in any agreement entered into pursuant
to the provisions of said Fourth Supplemental Indenture, in the event of the
selection for redemption of a portion only of the principal of this bond,
payment of the redemption price will be made only (a) upon presentation of this
bond for notation hereon of such payment of the portion of the principal of this
bond so called for redemption, or (b) upon surrender of this bond in exchange
for a bond or bonds of authorized denominations of the same series, for the
unredeemed balance of the principal amount of this bond.
The Indenture contains provisions permitting the Company and the Trustee,
with the consent of the holders of the not less than seventy-five percent in
principal amount of the bonds (exclusive of bonds disqualified by reason of the
Company's interest therein) at the time outstanding, including, if more than one
series of bonds shall be at the time outstanding, not less than sixty percent
in principal amount of each series affected, to effect, by an indenture
supplemental to the Indenture, modifications or alterations of the Indenture and
of the rights and obligations of the Company and of the holders of the bonds;
provided, however, that no such modification or alteration shall be made without
the written approval or consent of the registered holder hereof which will (a)
extend the maturity of this bond or reduce the rate or extend the time of
payment of interest hereon or reduce the amount of the principal hereof, or (b)
permit the creation of any lien, not otherwise permitted, prior to or on a
parity with the lien of the Indenture, or (c) reduce the percentage of the
principal amount of the bonds upon the approval or consent of the holders of
which modifications or alterations may be made as aforesaid.
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 the FAME Trustee if and to the extent that the FAME Trustee shall
have assigned its rights under the Loan 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 of this bond for cancellation and upon payment, if the
Company shall so require, of the stamp taxes and other governmental charges
provided for in said Fourth Supplemental Indenture, 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
-15-
authorized attorney, and thereupon a new bond of this series, for a like
principal amount, will be issued to the successor or assignee of the FAME
Trustee in exchange therefor, as provided in the Indenture.
The registered holder of this bond at his option may surrender the same for
cancellation at said office of the Trustee and to receive in exchange therefor
the same aggregate principal amount of registered bonds of the same series but
of other authorized denominations upon payment, if the Company shall so require,
of the stamp taxes and other governmental charges provided for in said Fourth
Supplemental Indenture and subject to the terms and conditions therein set
forth.
Neither the Company nor the Trustee shall be required to make transfers or
exchanges of bonds of this series for a period of ten days next preceding any
designation of bonds of said series to be redeemed, and neither the Company nor
the Trustee shall be required to make transfers or exchanges of any bonds
designated in whole for redemption or that part of any bond designated in part
for redemption. Subject to the provisions of said Fourth Supplemental
Indenture, if this bond is surrendered for any transfer or exchange
between the record date for any interest payment date and such interest payment
date, the new bond will be dated such interest payment date.
The Indenture provides that in the event of any default in payment of the
interest due on any interest payment date, such interest shall not be payable
to the holder of the bond on the original record date but shall be paid to the
registered holder of such bond on the subsequent record date established for
payment of such defaulted interest.
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 these 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.
-16-
[FORM OF TRUSTEE'S AUTHENTICATION CERTIFICATE FOR
BONDS OF THE 2008 SERIES]
This is one of the bonds, 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 2008 Series, when such interest shall be due and
payable (including, but not limited to, June 1, 2008), shall be
deemed to be, and shall be, satisfied and discharged if the Company
shall have paid all interest under the Loan Agreement then due and
payable. The obligation of the Company to make payments with
respect to the principal of Bonds of the 2008 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
(including, but not limited to, June 1, 2008), the Company shall
have paid the FAME Trustee for all amounts then due pursuant to
Sections 4.2 and 4.3 of the Loan 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 2008 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(l) of the Indenture. Whenever all of the Loan Agreement
Obligations shall have been satisfied, the aggregate principal
amount of all of the Bonds of the 2008 Series shall be surrendered
by the FAME Trustee to the Trustee for cancellation, and upon such
surrender shall be deemed fully paid.
Section 2.04. Redemption Provisions for the Bonds of the 2008
Series. Subject to the terms of the Loan Agreement applicable to
prepayment of the Loan Note, the Bonds of the 2008 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 an amount
equal to the Stated Principal Amount thereof or, if less, the
Effective Principal Amount thereof including interest accrued
thereon to the redemption date.
Upon the occurrence of certain Events of Default specified in
Section 9.03 of the FAME Indenture (including, but not limited to,
the failure to pay when due the principal of, and interest on, any
FAME Note), the Trustee may (and upon the written request of the
Holders of not less than 25% in the aggregate amount of FAME Notes
then outstanding, shall) declare the principal amount of all FAME
Notes then outstanding, together with the interest accrued thereon, to be
-17-
due and payable immediately. Upon any such declaration of
acceleration under the FAME Indenture, the FAME Trustee may
immediately exercise its rights (i) under the Loan Agreement to
declare all payments thereunder to be immediately due and payable,
and (ii) to demand redemption of the Bonds of the 2008 Series by
the Company. In such event, all Bonds of the 2008 Series then
outstanding shall be redeemed by the Company, on the date such FAME
Notes shall have become immediately due and payable, at the Stated
Principal Amount or, if less, the Effective Principal Amount
thereof including interest accrued thereon to the redemption date.
The Trustee may conclusively presume that no redemption of Bonds of the
2008 Series is required pursuant to this Section 2.04 unless and until the
Trustee shall have received a written notice from the FAME Trustee as described
in Section 12.01(l) of the Indenture.
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 2008 Series
at his address as shown on the Bond register for Bonds of the 2008
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 2008 Series called for redemption
waive notice thereof in writing and such waiver is filed with the
Trustee.
Section 2.05 Bondholders' List. Notwithstanding the provisions of
Section 11.02(B) of the Original Indenture, any one of the holders of the Bonds
of the 2008 Series shall be entitled to make application to the Trustee for a
Bondholders' list as provided for in Section 11.02.
Section 2.06 Mutilated, Lost or Destroyed Bonds. Notwithstanding the
provisions of Section 2.12 of the Original Indenture, for so long as any holder
of Bonds of the 2008 Series shall be an institutional holder, an unsecured
indemnity provided by such holder shall be deemed acceptable for purposes of
requesting a replacement bond for a mutilated, lost or destroyed Bond of the
2008 Series.
Section 2.07 Duration of Effectiveness of Article Two. This Article
shall be of force and effect only so long as any Bonds of the 2008 Series are
outstanding.
ARTICLE THREE
Modification of the Indenture
Section 3.01. Section 12.01 of the Indenture is hereby amended by adding
a new clause (l) to said Section which reads as follows:
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"(l) so long as any of the Bonds of the 2008 Series are
outstanding, upon receipt by the Trustee of a notice from
the holder of the Bonds of the 2008 Series that an event
of default has occurred under the Loan Agreement has
occurred 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 2008 Series are
outstanding.
ARTICLE FOUR
Authentication and Delivery of Bonds of the 2008 Series
Section 4.01. Upon the execution and delivery of this Fourth
Supplemental Indenture, Bonds of the 2008 Series in the aggregate
amount of Seven Million Five Hundred Forty Thousand Dollars
($7,540,000) 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. Additional
Bonds of the 2008 Series may be executed, authenticated and
delivered from time to time as permitted by the provisions of
Article Five of the Original Indenture.
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 Fourth 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 Fourth 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.
-19-
Section 5.04. Nothing in this Fourth 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 Fourth 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 Fourth 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 Fourth
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 Fourth Supplemental Indenture are inserted for
convenience only.
Section 5.07. All the covenants, stipulations, promises and
agreements in this Fourth 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 Fourth Supplemental Indenture is
dated for convenience and for the purpose of reference as of May 1,
1998, 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 Fourth 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.
-20-
IN WITNESS WHEREOF, MAINE PUBLIC SERVICE COMPANY has caused
this Fourth 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 Fourth 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, all as of the day and year first above written.
MAINE PUBLIC SERVICE COMPANY
/s/ Larry E. LaPlante
Name:Larry LaPlante
Title:Vice President
CORPORATE SEAL
Attest:
/s/ Kurt A. Tornquist
Name: Kurt A. Tornquist
Title: Assistant Secretary
Signed, sealed and delivered
by MAINE PUBLIC SERVICE COMPANY
in the presence of:
/s/ Marilyn L. Bouchard
Marilyn L. Bouchard
/s/ Alice E. Shepard
Alice E. Shepard
-21-
IBJ SCHRODER BANK & TRUST
COMPANY
/s/ Luis Perez
Name:Luis Perez
Title:Vice President
CORPORATE SEAL
Attest:
/s/ Max Volmar
Name: Max Volmar
Title: Assistant Secretary
Signed, sealed and delivered
by IBJ SCHRODER BANK & TRUST
COMPANY in the presence of:
/s/ Terence Rawlins
Name: Terence Rawlins
Title: Assistant Vice President
Name:
Title:
-22-
STATE OF MAINE )
: ss.:
COUNTY OF AROOSTOOK )
May 26, 1998
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
-23-
STATE OF NEW YORK )
: ss.:
COUNTY OF NEW YORK )
May 27, 1998
Then personally appeared the above-named Luis Perez, 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/ Michael W. Lofton
Notary Public
My Commission expires: Dec. 29, 1999
-24-
Exhibit 10(w)
ASSET PURCHASE AGREEMENT
AMONG
MAINE PUBLIC SERVICE COMPANY,
MAINE AND NEW BRUNSWICK
ELECTRICAL POWER COMPANY, LIMITED
AND
WPS POWER DEVELOPMENT, INC.
Dated As Of: July 7, 1998
TABLE OF CONTENTS
Page
ARTICLE I DEFINITIONS . . . . . . . . . . . . . . . . . . . . .1
1.1 Definitions. . . . . . . . . . . . . . . . . . . . . .1
ARTICLE II PURCHASE AND SALE. . . . . . . . . . . . . . . . . 12
2.1 The Purchase and Sale. . . . . . . . . . . . . . . . 12
2.2 Excluded Assets. . . . . . . . . . . . . . . . . . . 12
2.3 Assumed Obligations. . . . . . . . . . . . . . . . . 13
2.4 Excluded Liabilities . . . . . . . . . . . . . . . . 15
ARTICLE III PURCHASE PRICE. . . . . . . . . . . . . . . . . . 18
3.1 Purchase Price . . . . . . . . . . . . . . . . . . . 18
3.2 Purchase Price Adjustment. . . . . . . . . . . . . . 18
3.3 Allocation of Purchase Price and Assumed
Obligations. . . . . . . . . . . . . . . . . . . . . 18
3.4 HST Election . . . . . . . . . . . . . . . . . . . . 19
3.5 Proration. . . . . . . . . . . . . . . . . . . . . . 19
ARTICLE IV THE CLOSING. . . . . . . . . . . . . . . . . . . . 20
4.1 Time and Place of Closing. . . . . . . . . . . . . . 20
4.2 Payment of Purchase Price. . . . . . . . . . . . . . 20
4.3 Deliveries by the Sellers. . . . . . . . . . . . . . 20
4.4 Deliveries by the Buyer. . . . . . . . . . . . . . 22
ARTICLE V REPRESENTATIONS AND WARRANTIES OF THE SELLERS . . . 23
5.1 Organization; Qualification. . . . . . . . . . . . . 23
5.2 Authority Relative to this Agreement . . . . . . . . 23
5.3 Consents and Approvals; No Violation . . . . . . . . 24
5.4 Reports. . . . . . . . . . . . . . . . . . . . . . . 25
5.5 Financial Statements . . . . . . . . . . . . . . . . 25
5.6 Undisclosed Liabilities. . . . . . . . . . . . . . . 25
5.7 Absence of Certain Changes or Events . . . . . . . . 25
5.8 Title to and Condition of Properties . . . . . . . . 26
5.9 Leases . . . . . . . . . . . . . . . . . . . . . . . 27
5.10 Insurance. . . . . . . . . . . . . . . . . . . . . . 28
5.11 Environmental Matters. . . . . . . . . . . . . . . . 28
5.12 Labor Matters. . . . . . . . . . . . . . . . . . . . 29
5.13 ERISA; Benefit Plans.. . . . . . . . . . . . . . . . 29
5.14 Condemnation . . . . . . . . . . . . . . . . . . . . 31
5.15 Certain Contracts and Arrangements . . . . . . . . . 32
5.16 Legal Proceedings, etc . . . . . . . . . . . . . . . 32
5.17 Permits. . . . . . . . . . . . . . . . . . . . . . . 33
5.18 Regulation as a Utility. . . . . . . . . . . . . . . 33
5.19 Taxes. . . . . . . . . . . . . . . . . . . . . . . . 33
5.20 Sufficiency of Purchased Assets. . . . . . . . . . . 34
5.21 Buyer's Knowledge. . . . . . . . . . . . . . . . . . 34
ARTICLE VI REPRESENTATIONS AND WARRANTIES OF THE BUYER. . . . 34
6.1 Organization . . . . . . . . . . . . . . . . . . . . 34
6.2 Authority Relative to this Agreement . . . . . . . . 34
6.3 Consents and Approvals; No Violation . . . . . . . . 35
6.4 Regulation as a Utility. . . . . . . . . . . . . . . 36
6.5 Disclosure . . . . . . . . . . . . . . . . . . . . . 36
ARTICLE VII COVENANTS OF THE PARTIES. . . . . . . . . . . . . 36
7.1 Conduct of Business Relating to the Purchased
Assets . . . . . . . . . . . . . . . . . . . . . . . 36
7.2 Access to Information. . . . . . . . . . . . . . . . 38
7.3 Expenses . . . . . . . . . . . . . . . . . . . . . . 40
7.4 Further Assurances . . . . . . . . . . . . . . . . . 40
7.5 Public Statements. . . . . . . . . . . . . . . . . . 41
7.6 Consents and Approvals; Financing. . . . . . . . . . 41
7.7 Fees and Commissions . . . . . . . . . . . . . . . . 42
7.8 Tax Matters. . . . . . . . . . . . . . . . . . . . . 42
7.9 Supplements to Schedules . . . . . . . . . . . . . . 43
7.10 Employees. . . . . . . . . . . . . . . . . . . . . . 43
7.11 Risk of Loss . . . . . . . . . . . . . . . . . . . . 47
7.12 Real Estate Title; Title Insurance; Surveys. . . . . 48
7.13 Wyman Agreements . . . . . . . . . . . . . . . . . . 49
ARTICLE VIII CONDITIONS PRECEDENT . . . . . . . . . . . . . . 50
8.1 Conditions to Each Party's Obligations . . . . . . . 50
8.2 Conditions to Obligations of the Buyer . . . . . . . 50
8.3 Conditions to Obligations of the Sellers . . . . . . 52
-ii-
ARTICLE IX INDEMNIFICATION. . . . . . . . . . . . . . . . . . 53
9.1 Indemnification. . . . . . . . . . . . . . . . . . . 53
9.2 Defense of Claims. . . . . . . . . . . . . . . . . . 55
ARTICLE X TERMINATION AND ABANDONMENT . . . . . . . . . . . . 57
10.1 Termination. . . . . . . . . . . . . . . . . . . . . 57
10.2 Procedure and Effect of Termination. . . . . . . . . 57
ARTICLE XI MISCELLANEOUS PROVISIONS . . . . . . . . . . . . . 58
11.1 Amendment and Modification . . . . . . . . . . . . . 58
11.2 Waiver of Compliance; Consents . . . . . . . . . . . 58
11.3 Notices. . . . . . . . . . . . . . . . . . . . . . . 58
11.4 Assignment . . . . . . . . . . . . . . . . . . . . . 59
11.5 Governing Law. . . . . . . . . . . . . . . . . . . . 59
11.6 Counterparts . . . . . . . . . . . . . . . . . . . . 60
11.7 Interpretation . . . . . . . . . . . . . . . . . . . 60
11.8 Schedules and Exhibits . . . . . . . . . . . . . . . 60
11.9 Entire Agreement . . . . . . . . . . . . . . . . . . 60
-iii-
EXHIBITS:
Bill of Sale A
Buy-Back Agreement B
Continuing Site Agreement C
Instrument of Assumption (MPS Liabilities) D-1
Instrument of Assumption (MNB Liabilities) D-2
Interconnection Agreements E
Form of Opinion (Sellers' U.S. Counsel) G-1
Form of Opinion (Sellers' Canadian Counsel) G-2
Form of Opinion (Buyer's U.S. Counsel) H
SCHEDULES:
Canadian Personal Property 1.1(a)(7)(iii)
FERC Licenses 1.1(a)(32)
NEB Licenses 1.1(a)(51)
Permitted Encumbrances 1.1(a)(55)
Transferable Permits 1.1(a)(70)
U.S. Personal Property 1.1(a)(72)(iii)
Excluded Facilities and Equipment 2.2(d)
Qualifications and Licenses to do Business 5.1
Consents, Approvals, Violations, Defaults of Sellers 5.3
Undisclosed Liabilities 5.6
Material Changes and Events 5.7
Title Exceptions 5.8(a)
Condition of Assets 5.8(b)
Real Estate 5.8(c)
Real Property Leases 5.9
Insurance Exceptions 5.10
Environmental Permits, Agreements and Consent Order 5.11
Employment Claims and Exceptions 5.12
Benefit Plans 5.13(a)
ERISA Fundings Obligations and Exceptions 5.13(b)
Real Estate Condemnation 5.14
Contracts, Agreements, and Personal Property Leases 5.15(a)
Exception to Contractual Obligations 5.15(b)
Material Defaults 5.15(c)
Legal Proceedings 5.16
Material Permits (other than Environmental Permits)
Violations of Material Permits, Related Laws, Statutes, Etc. 5.17
Tax Exceptions 5.19
Consents, Approvals, Violations and Defaults of Buyer 6.3
Index of Disclosure Materials 6.5
Maintenance and Capital Expenditures 7.1
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Buyer's Environmental Testing 7.2
Employees 7.10(a)
Labor Agreements 7.10(b)
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THIS ASSET PURCHASE AGREEMENT, dated as of July 7, 1998 (this "Agreement"),
by and among MAINE PUBLIC SERVICE COMPANY, a Maine corporation ("MPS"), MAINE
AND NEW BRUNSWICK ELECTRICAL POWER COMPANY, LIMITED, a New Brunswick
corporation ("MNB", and together with MPS, the "Sellers"), and WPS POWER
DEVELOPMENT, INC., a Wisconsin corporation ("PDI" or the "Buyer"),
W I T N E S S E T H:
WHEREAS, the Buyer desires to purchase (or to cause its designee to
purchase), and the Sellers desire to sell, the U.S. Assets and the Canadian
Assets (each as defined herein and together, the "Purchased Assets"), and the
Buyer has agreed to assume (or to cause its designee to assume) the Assumed
Obligations (as defined herein), in each case upon the terms and conditions
hereinafter set forth in this Agreement;
NOW, THEREFORE, in consideration of the mutual covenants, representations,
warranties and agreements hereinafter set forth, and intending to be legally
bound hereby, the parties hereto agree as follows:
ARTICLE I
DEFINITIONS
1.1 Definitions.
(a) As used in this Agreement, the following terms have the
meanings specified in this Section 1.1(a).
(1) "Affiliate" has the meaning set forth in Rule 12b-2 of the
General Rules and Regulations under the Exchange Act.
(2) "assessment" includes a reassessment.
(3) "Bill of Sale" means a bill of sale to be delivered by a
Seller at the Closing with respect to the Purchased Assets of such Seller
which constitute personal property and which are to be transferred at the
Closing, substantially in the form of Exhibit A hereto.
(4) "Business Day" means any day other than Saturday, Sunday and
any day which is a legal holiday or a day on which banking institutions in
Portland, Maine are authorized by law or other governmental action to
close.
(5) "Buy-Back Agreement" means the Buy-Back Agreement
substantially in the form of Exhibit B hereto, dated the date of the
Closing, pursuant to which the Buyer or its designee agrees to sell to MPS,
and MPS agrees to purchase from the Buyer or its designee, energy and
capacity as provided therein.
(6) "Buyer Representatives" means the Buyer's accountants,
employees, counsel, environmental consultants, financial advisors and other
authorized representatives.
(7) "Canadian Assets" means, subject to Section 2.2, all of the
right, title and interest in, to and under the real and personal property,
tangible or intangible, owned by either of the Sellers and constituting the
Tinker Generating Station or used principally for generation purposes in
connection with such dams and reservoirs and which are located in Aroostook
Junction, New Brunswick, or which constitute transmission and distribution
assets located in New Brunswick, Canada, including, but not limited to, the
following assets owned by either of the Sellers:
(i) the Real Estate (including all buildings, structures,
fixtures and other improvements thereon, all applicable easements and
other access rights, and all other rights and privileges belonging
or appertaining thereto) described on Schedule 5.8(c) as associated
with the Canadian Assets (the "Canadian Real Property");
(ii) inventories of supplies, materials and critical spares
located on or in transit to the Canadian Real Property on the Closing
Date;
(iii) the machinery, equipment, vehicles, furniture and
other personal property located on the Canadian Real Property on the
Closing Date, including, without limitation, the items of personal
property included in Schedule 1.1(a)(7)(iii) as being associated
with the Canadian Assets, and all warranties against manufacturers or
vendors relating thereto, to the extent assignable to the Buyer or its
designee and subject to the receipt of any necessary consents;
(iv) the contracts, agreements, and real and personal
property leases listed on Schedules 5.9, 5.15(a) and 7.10(b) as being
associated with the Canadian Assets;
(v) the Transferable Permits listed on Schedule 1.1(a)(70)
as being associated with the Canadian Assets; and
(vi) all books, operating records, operating, safety and
maintenance manuals, engineering design plans, blueprints and as-built
plans, specifications, procedures and similar items relating
specifically to the aforementioned assets other than books of account.
(8) "Capital Expenditures" means those capital
expenditures which are identified as capital expenditures
with respect to the Purchased Assets and in the amounts
identified on Schedule 7.1.
(9) "Capital Improvements" means those
modifications or improvements to the Purchased Assets
described on Schedule 7.1 as associated with the Capital
Expenditures.
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(10) "Caribou Fossil Assets" means those portions of Caribou
Station relating to the generation of electricity through fossil fuels.
(11) "Caribou Hydro Assets" means those portions of the Caribou
Station relating to the generation of electricity through hydro power.
(12) "Caribou Station" means the electric generating facility
located in Caribou, within the County of Aroostook, Maine and known as the
Caribou Station.
(13) "CERCLA" means the Federal Comprehensive Environmental
Response, Compensation and Liability Act, as amended.
(14) "Closing" means the closing of the sale of the Purchased
Assets and the assumption of the Assumed Obligations as described in
Section 4.1 hereof.
(15) "Closing Date" means the actual date of the Closing.
(16) "Closing Documents" means, collectively, this Agreement, the
Bills of Sale, the Buy-Back Agreement, the Continuing Site Agreement, the
Instruments of Assumption, the Interconnection Agreements, and each of the
documents, instruments, certificates, opinions, and agreements which
are required to be delivered pursuant hereto and thereto.
(17) "COBRA" means the health care continuation coverage
provisions of the Consolidated Omnibus Budget Reconciliation Act of 1986,
as amended.
(18) "Code" means the Internal Revenue Code of 1986, as amended.
(19) "Confidentiality Agreement" means the Confidentiality
Agreement, dated October 20, 1997, between MPS and PDI.
(20) "Continuing Site Agreement" means the Continuing
Site/Interconnection Agreement in substantially the form of Exhibit C
hereto, dated the date of the Closing, between MPS and the Buyer or its
designee.
(21) "DEP" means the Maine Department of Environmental
Protection.
(22) "designee of the Buyer", "Buyer's designee", "its designee"
(when referring to the Buyer), and any similar phrase, means one or more
wholly owned, direct or indirect subsidiaries of the Buyer formed in a
jurisdiction of the United States to own all title and interests in and
to the U.S. Assets, the Canadian Assets, or both.
(23) "Easements" means, with respect to the Purchased Assets, the
reservations of easements to be included in the deeds of conveyance with
respect to such assets, or, in the case of the Flo's Inn Station, the
easement to be granted to Buyer or its designee, substantially as set forth
in Schedule 5.8(c) hereto.
-3-
(24) "Encumbrances" means any mortgages, pledges, liens, security
interests, conditional and installment sale agreements, activity and use
limitations, conservation easements, deed restrictions, encumbrances and
charges of any kind.
(25) "Environmental Laws" means all federal, state, provincial,
foreign and local laws, regulations, rules, ordinances, codes, decrees,
judgments, directives, or judicial or administrative orders relating to
pollution or protection of the environment, natural resources or human
health and safety, including, without limitation, laws relating to Releases
or threatened Releases of Hazardous Substances (including, without
limitation, into or through ambient air, surface water, groundwater, land
surface and subsurface strata) or otherwise relating to the manufacture,
processing, distribution, use, treatment, storage, Release, transport or
handling of Hazardous Substances, including without limitation the Clean
Water Act (United States), the Clean Air Act (United States), the Resource
Conservation and Recovery Act (United States), the Toxic Substances Control
Act (United States), CERCLA (United States), Fisheries Act (Canada),
Environmental Assessment Act (Canada), Navigable Waters Protection Act
(Canada), Clean Air Environmental Act (New Brunswick, Canada), Clean Water
Act (New Brunswick, Canada), and Pesticides Control Act (New Brunswick,
Canada), in each case as amended, and their state or provincial and
local counterparts.
(26) "ERISA" means the Employee Retirement Income Security Act
of 1974, as amended.
(27) "ERISA Affiliate" means any corporation that is or ever has
been a member of a controlled group of corporations with the Sellers, any
trade or business (whether or not incorporated) that is or ever has been
under common control with the Sellers, any member of a current or former
affiliated service group including the Sellers, and any entity that is or
ever has been required to be treated as a single employer with the Sellers,
under Section 414(b), (c), (m), or (o) of the Code.
(28) "Exchange Act" means the Securities Exchange Act of 1934,
as amended.
(29) "Excise Tax Act (Canada)" means the Excise Tax Act, R.S.C
1985 c.E-15, as amended.
(30) "Federal Power Act" means the Federal Power Act of 1935.
(31) "FERC" means the Federal Energy Regulatory Commission.
(32) "FERC Licenses" means the licenses identified in Schedule
1.1(a)(32) hereto.
(33) "Flo's Inn Station" means the electric generating facilities
located in Presque Isle, within the County of Aroostook, Maine and known
as the Flo's Inn Generating Station.
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(34) "generally accepted accounting principles" means generally
accepted accounting principles in the United States.
(35) "Hazardous Substances" means (a) any petrochemical or
petroleum products, oil or coal ash, radioactive materials, radon gas,
asbestos in any form that is or could become friable, urea formaldehyde
foam insulation and transformers or other equipment that contain
dielectric fluid which may contain levels of polychlorinated biphenyls; (b)
any chemicals, materials or substances defined as or included in the
definition of "hazardous substances", "hazardous wastes", "hazardous
materials", "restricted hazardous materials", "extremely hazardous
substances", "toxic substances", "contaminants" or "pollutants" or words
of similar meaning and regulatory effect; or (c) any other chemical,
material or substance, exposure to which is prohibited, limited or
regulated by any applicable Environmental Law.
(36) "HIPAA" means the Health Insurance Portability and
Accountability Act of 1996, as amended.
(37) "Holding Company Act" means the Public Utility Holding
Company Act of 1935, as amended.
(38) "Houlton Station" means the electric generating facilities
located in Houlton, Maine and known as the Houlton Station.
(39) "HSR Act" means the Hart-Scott-Rodino Antitrust Improvements
Act of 1976, as amended.
(40) "HST" means the tax levied under Part IX of the Excise Tax
Act (Canada).
(41) "Income Tax" means any federal, state, provincial, local or
foreign Tax (a) based upon, measured by or calculated with respect to net
income, profits or receipts (including, without limitation, capital gains
Taxes and minimum Taxes) or (b) based upon, measured by or calculated with
respect to multiple bases (including, without limitation, corporate
franchise taxes) if one or more of the bases on which such Tax may be
based, measured by or calculated with respect to, is described in clause
(a), in each case together with any interest, penalties, or
additions to such Tax.
(42) "Indentures" means:
(i) the Indenture of Mortgage and Deed of Trust, dated as
of October 1, 1945, between MPS and First Trust of Illinois
(successor to Continental Illinois National Bank and Trust
Company of Chicago), as Trustee, as supplemented; and
(ii) the Indenture of Second Mortgage and Deed of Trust, dated
as of October 1, 1985, between MPS and IBJ Schroder Bank & Trust
Company (successor to J. Henry Schroder Bank & Trust Company),
as Trustee, as supplemented.
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(43) "Instruments of Assumption" means the Instrument of
Assumption substantially in the form of Exhibit D-1 hereto relating to the
assumption by the Buyer or its designee of the liabilities and obligations
of MPS described therein and the Instrument of Assumption substantially in
the form of Exhibit D-2 hereto relating to the assumption by the Buyer or
its designee of the liabilities and obligations of MNB described therein,
in each case, to be delivered at the Closing.
(44) "Interconnection Agreements" means the Interconnection
Agreements substantially in the form of Exhibit E, dated the date of the
Closing, between MPS and the Buyer or its designee.
(45) "Knowledge", "to the knowledge of", and any similar phrase,
(i) when referring to the Sellers, means the actual and conscious knowledge
of the following members of management of MPS: Paul R. Cariani, Frederick
C. Bustard, Stephen A. Johnson, Edward Howard, Larry E. LaPlante, David
Holabird, or Peter Louridas after reasonable inquiry by them of selected
employees of the Sellers whom they believe, in good faith, to be the
persons generally responsible for the subject matters to which the
knowledge is pertinent; and (ii) when referring to Buyer, the actual and
conscious knowledge of the following persons: Gerald L. Mroczkowski,
Richard J. Suslick, Keith M. Uffelman, Richard R. Heidel, Thomas G.
Balzola, Lisa M. Cribben, and Gregory W. Egtvedt, after reasonable inquiry
by them of selected employees of Buyer whom they believe, in good faith,
to be the persons generally responsible for the subject matters to which
the knowledge is pertinent.
(46) "Labor Agreement" means a collective bargaining agreement
or other employment-related agreement identified on Schedule 7.10(b).
(47) "Maintenance Expenditures" means those maintenance
expenditures which are identified as maintenance expenditures with respect
to the Purchased Assets and in the amounts identified on Schedule 7.1.
(48) "Maintenance and Capital Expenditures Amount" means the
aggregate amount of all funds actually expended on, or for which
liabilities were accrued in accordance with generally accepted accounting
principles applied on a consistent basis with respect to, Maintenance
Expenditures and Capital Expenditures by the Sellers, if any, during the
period beginning on the date hereof and ending on the Closing Date, but not
in excess of the aggregate amount set forth in Schedule 7.1.
(49) "Material Adverse Effect" means any change or changes in,
or effect on, the Purchased Assets, the operation, maintenance or condition
(financial or otherwise) of the Purchased Assets, or the business of the
Sellers in connection therewith after the date of this Agreement, or
any change or changes in, or effect on, the Assumed Obligations after the
date of this Agreement, in each case that is, individually, or in the
aggregate are materially adverse to the Purchased Assets, the operation,
maintenance, or condition (financial or otherwise) of the Purchased
Assets, the business of the Sellers, or the intended business of the Buyer
as contemplated herein in connection therewith, or to the
-6-
Assumed Obligations, taken as a whole, other than (i) any change or effect
resulting from changes in the international, national, U.S., Canadian,
regional or local wholesale or retail markets for electric power, (ii) any
change or effect resulting from changes in the international, national,
U.S., Canadian, regional or local markets for any fuel used at the
Purchased Assets, (iii) any change or effect resulting from changes in the
North American, national, U.S., Canadian, regional or local electric
transmission systems, (iv) any changes or effects resulting from changes
in U.S., Canadian, state, provincial or local laws, regulations or
ordinances affecting the Purchased Assets, and (v) any materially adverse
change in or effect on the Purchased Assets, the operation, maintenance or
condition (financial or otherwise) of the Purchased Assets, the business
of the Sellers (or of the Buyer after the Closing, as the case may be) in
connection therewith, or the Assumed Obligations which is cured (including
by the payment of money) by the Sellers to the reasonable satisfaction of
the Buyer before the Termination Date. Notwithstanding the foregoing, the
term "Material Adverse Effect" with respect to matters affecting the Real
Estate and the Easements shall be measured not from the date of this
Agreement but shall initially be measured without reference to any time
period and, with respect to matters identified after the sixty-day period
referred to in Section 7.12(b), shall be measured from the effective date
of the title insurance commitments delivered on the Initial Title Review
Date referred to in Section 7.12(a).
(50) "Millinocket Facility" means the hydro electric storage dam
located on Millinocket Lake in the unorganized territory, T7 R9 WELS,
Piscataquis County, Maine and known as the Millinocket Facility.
(51) "NEB Licenses" means the licenses, permits and certificates
identified in Schedule 1.1(a)(51) hereto.
(52) "NPDES" means the National Pollutant Discharge Elimination
System.
(53) "Pension Benefits Act" means the Pension Benefits Act,
S.N.B. 1987, C. P- 5.1.
(54) "Permits" means all licenses, permits, exemptions, approvals
and authorizations of any nature issued by any local, state, provincial,
federal or foreign governmental agency applicable to the construction,
ownership, operation, maintenance or repair of the Purchased Assets or any
part thereof or to the performance of the Assumed Obligations.
(55) "Permitted Encumbrances" means (i) those Encumbrances set
forth in Schedule 1.1(a)(55); (ii) the Easements; (iii) those exceptions
to title to the Purchased Assets listed in Schedule 5.8(a); (iv) all
exceptions, restrictions, easements, charges, rights of way and monetary
and non-monetary encumbrances which are set forth in the FERC Licenses and
the NEB Licenses, except for such Encumbrances that secure indebtedness;
(v) with respect to any date before the Closing Date, Encumbrances created
by the Indentures; (vi) statutory liens for current taxes or assessments
not yet due or delinquent or, with respect to any date before the Closing
Date, the validity of which is being
-7-
contested in good faith by appropriate proceedings; (vii) mechanics',
carriers', workers', repairers' and other similar liens arising or incurred
in the ordinary course of business relating to obligations as to which
there is no default on the part of the Sellers or, with respect to any date
before the Closing Date, the validity of which is being contested in good
faith by appropriate proceedings; (viii) zoning, entitlement, conservation
restriction and other land use and environmental regulations by govern-
mental authorities which do not materially detract from the value of the
Purchased Assets as currently used or materially interfere with the present
use of the Purchased Assets or, individually or in the aggregate, create
a Material Adverse Effect; and (ix) such other liens, imperfections in or
failure of title, charges, easements, restrictions and encumbrances which
do not materially detract from the value of the Purchased Assets as
currently used or materially interfere with the present use of the
Purchased Assets and neither secure indebtedness, nor individually or in
the aggregate create a Material Adverse Effect.
(56) "Person" means any individual, partnership, limited
liability company, joint venture, corporation, trust, unincorporated
organization or governmental entity or any department or agency thereof.
(57) "Proprietary Information" has the meaning referred to in
Section 7.2(b).
(58) "PUC" means the Maine Public Utilities Commission.
(59) "Release" means release, spill, leak, discharge, dispose of,
pump, pour, emit, empty, inject, leach, dump or allow to escape into or
through the environment.
(60) "SEC" means the Securities and Exchange Commission.
(61) "Securities Act" means the Securities Act of 1933, as
amended.
(62) "Sellers' Agreements" means those agreements listed on
Schedules 5.9 and 5.15(a) and the Labor Agreements.
(63) "Sellers' Employee Transition Plan" means the Sellers'
Employee Transition Plan in the form approved by the Buyer and the PUC on
or before the Closing Date.
(64) "Sellers' Representatives" means the Sellers' accountants,
employees, counsel, financial advisors and other authorized
representatives.
(65) "Squa Pan Station" means the hydro-electric facility located
in Masardis, within the County of Aroostook, Maine and known as Squa Pan
Station.
(66) "Subsidiary" when used in reference to any other Person
means any entity of which outstanding securities having ordinary voting
power to elect a majority of the Board of Directors or other Persons
performing similar functions of such entity are owned directly or
indirectly by such other Person.
-8-
(67) "Tax" or "Taxes" means all taxes, charges, fees, levies,
penalties or other assessments imposed by any United States or foreign
federal, state, provincial, or local taxing authority, including, but not
limited to, HST, income, excise, property, sales, transfer, franchise,
payroll, withholding, social security or other taxes, including any
interest, penalties or additions attributable thereto.
(68) "Tax Return" means any return, report, information return
or other document (including any related or supporting information)
required to be supplied to any authority with respect to Taxes.
(69) "Tinker Generating Station" means the hydroelectric facility
located in Aroostook Junction, New Brunswick, Canada and known as the
Tinker Generating Station, together with the related diesel generating
assets and the transmission and distribution facilities owned by
MNB and located in New Brunswick, Canada.
(70) "Transferable Permits" means those Permits and Environmental
Permits and any applications pertaining thereto set forth in Schedule
1.1(a)(70), to the extent assignable to the Buyer or its designee and
subject to the receipt of any necessary consents and approvals.
(71) "Transferring Employee Records" means all personnel files
related to the Sellers' personnel who will become employees of the Buyer.
(72) "U.S. Assets" means, subject to the Easements in favor of
MPS and Section 2.2, all of Sellers' right, title and interest in, to and
under the real and personal property, tangible or intangible, and
constituting the Flo's Inn Station, the Houlton Station, the Millinocket
Facility, the Squa Pan Station and the Caribou Station or used
principally for generation purposes in connection with the Flo's Inn
Station, the Houlton Station, the Millinocket Facility, the Squa Pan
Station or the Caribou Station, or used principally in connection with the
Tinker Generating Station, but not including any of MPS's transmission and
distribution assets, and including MPS's entire interest in the Wyman
Station, and, in the case of any hydroelectric facilities, including any
generating assets which are located within the applicable FERC project
license boundary, and together with, in each case, all of MPS's right,
title and interest under any private and special laws of Maine
relating to any of the U.S. Assets or the Canadian Assets, including, but
not limited to, the following assets owned by MPS or MNB:
(i) the Real Estate (including all buildings, structures,
fixtures and other improvements thereon, all applicable easements and
other access rights and all other rights and privileges belonging or
appertaining thereto) described on Schedule 5.8(c) as associated with
the Millinocket Facility, the Squa Pan Station, the Flo's Inn Station,
the Caribou Station, or the Tinker Generating Station, but not the
Houlton Station, and, with respect to the Flo's Inn Station, only to
the extent of the Easement therefor (the "U.S. Real Property");
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(ii) all inventories of fuels, supplies, materials and
critical spares located on or in transit to the U.S. Real Property on
the Closing Date;
(iii) the machinery, equipment, vehicles, furniture and
other personal property located on the U.S. Real Property or the
Houlton Station on the Closing Date, including, without limitation,
the items of personal property included in Schedule 1.1(a)(72)(iii)
as being associated with any of the Flo's Inn Station, the Houlton
Station, the Millinocket Facility, the Squa Pan Station or the Caribou
Station, and all warranties against manufacturers or vendors
relating thereto, to the extent assignable to the Buyer or its
designee and subject to the receipt of any necessary consents;
(iv) the contracts, agreements, and real and personal
property leases listed on Schedules 5.9, 5.15(a) and 7.10(b) as being
associated with any of the Flo's Inn Station, the Millinocket
Facility, the Squa Pan Station or the Caribou Station;
(v) the Transferable Permits listed on Schedule 1.1(a)(70)
as being associated with any of the Flo's Inn Station, the Millinocket
Facility, the Squa Pan Station or the Caribou Station;
(vi) all books, operating records, operating, safety and
maintenance manuals, engineering design plans, blueprints and as-built
plans, specifications, procedures and similar items of the Sellers
relating specifically to the aforementioned assets other than
books of account; and
(vii) MPS's entire interest in Unit 4 of Wyman Station, as
affected by the Wyman Agreements, and MPS's associated rights in and
to the categories of assets disclosed in clauses (i) through (vi)
hereof relating to Unit 4 of Wyman Station.
(73) "WARN Act" means the Federal Worker Adjustment Retraining
and Notification Act of 1988.
(74) "Wyman Agreements" means (i) the William F. Wyman Unit No.
4 Agreement for Joint Ownership, Construction and Operation, dated as of
November 1, 1974, by and among Central Maine Power Company, Bangor
Hydro-Electric Company, MPS, Boston Edison Company, Fitchburg Gas and
Electric Light Company, Montaup Electric Company, New England Power
Company, New Bedford Gas and Edison Light Company, Newport Electric
Corporation, Public Service Company of New Hampshire, Central Vermont
Public Service Corporation, Green Mountain Power Corporation, City of
Burlington Electric Department, Village of Lyndonville Electric Department,
and Massachusetts Municipal Wholesale Electric Company, as amended by
Amendments Nos. 1, 2 and 3 dated, respectively, June 30, 1975, August 16,
1976, and December 31, 1978, and (ii) the William F. Wyman Unit No. 4
Transmission Agreement, dated as of November
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1, 1974, by and among MPS and the other parties to the agreement described
in clause (i) above.
(75) "Wyman Station" means the electric generating facilities
known as the W.F. Wyman Station and located in Yarmouth, Maine.
(b) Each of the following terms has the meaning specified in the
Section set forth opposite such term:
Term Section
Adjustment Amount 3.2(a)
Adjustment Statement 3.2(a)
Assumed Obligations 2.3(b)
Benefit Plans 5.13(a)
Buyer Benefit Plans 7.10(e)
Buyer Required Regulatory Approvals 6.3(b)
Buyer's Window 7.10(a)
Buyer's 401(k) Plan 7.10(f)
Closing 4.1
Closing Date 4.1
Conditions 4.1
Direct Claim 9.2(c)
Employees 7.10(a)
Environmental Permits 5.11(a)
ERISA Affiliate Plans 2.4(10)
Excluded Assets 2.2
Excluded Liabilities 2.4
Final Order 8.1(c)
IBEW 7.10(a)
IBEW Agreements 7.10(b)
Indemnifiable Loss 9.1(a)
Indemnifying Party 9.1(d)
Indemnitee 9.1(c)
Independent Appraiser 3.3
Inventory Adjustment Amount 3.2(a)
Inventory Survey 3.2(a)
Observers 7.1(d)(1)
Pension Plans 5.13(a)
Purchased Assets Recitals
Purchase Price 3.1
Real Estate 5.8(c)
Replacement Welfare Plans 7.10(d)
Required Permits 5.17
Sellers Balance Sheets 5.5
Sellers Required Regulatory Approvals 5.3(b)
Sellers' Non-Union 401(k) Plan 7.10(f)
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Termination Date 10.l(b)
Third Party Claim 9.2(a)
Transferred Employees 7.10(a)
Transferred IBEW Employees 7.10(b)
Transferred Non-Union Employees 7.10(c)
Transition Committee 7.1(c)
Welfare Plans 5.13(a)
ARTICLE II
PURCHASE AND SALE
2.1 The Purchase and Sale.
(a) Upon the terms and subject to the satisfaction of the conditions
contained in this Agreement, at the Closing the Sellers will sell, assign,
convey, transfer and deliver to the Buyer or its designee, and the Buyer or its
designee will purchase and acquire from Seller, free and clear of all
Encumbrances (except for Permitted Encumbrances) all of the Sellers' right,
title and interest in, to and under the real and personal property, tangible or
intangible, owned by the Sellers and constituting the Purchased Assets.
(b) At the Closing, the Buyer or its designee and MPS will execute and
deliver to one another the Buy-Back Agreement, the Continuing Site Agreement,
and the Interconnection Agreements.
2.2 Excluded Assets. Notwithstanding any provision herein to the
contrary, the Purchased Assets shall not include the following assets of the
Sellers (herein referred to as the "Excluded Assets"):
(a) all cash, cash equivalents, bank deposits, accounts receivable, and
any income, sales, payroll or other tax receivables;
(b) certificates of deposit, shares of stock, securities, bonds,
debentures, evidences of indebtedness, and except in respect of MPS's interest
in the Wyman Station, interests in joint ventures, partnerships, limited
liability companies and other entities;
(c) the names Maine Public Service Company, Maine and New Brunswick
Electrical Power Company Limited, or any related or similar names, and any trade
names, trademarks, service marks, copyrights or logos;
(d) the transmission, distribution, substation and communication
facilities and related support equipment, including but not limited to those
described or referred to in Schedule 2.2(d), other than any transmission and
distribution assets owned by MNB and located in Canada;
(e) any refund, credit or other amount due (i) related to real or personal
property Taxes paid prior to the Closing Date in respect of the Purchased
Assets, whether such refund is
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received as a payment or as a credit against future real or personal property
Taxes payable, or (ii) arising under any Sellers' Agreement and relating to a
period before the Closing Date;
(f) all personnel records other than Transferring Employee Records;
(g) the real property interests associated with the Houlton Station; and
(h) the portion of the Caribou Facility consisting of the real property
under and near the electrical substations and related equipment at the
Caribou Station being retained by MPS, being approximately 0.27 acres
between the diesel plant and the filter plant, the exact description
of which portion shall be agreed upon by MPS and Buyer.
2.3 Assumed Obligations.
(a) On the Closing Date, the Buyer shall deliver to the Sellers the
Instruments of Assumption pursuant to which the Buyer or its designee shall
assume and agree to discharge all of the liabilities and obligations of the
Sellers, direct or indirect, known or unknown, absolute or contingent, which
relate to Purchased Assets, other than the Excluded Liabilities, in accordance
with the respective terms and subject to the respective conditions thereof,
including without limitation, the following liabilities and obligations:
(1) all liabilities and obligations of the Sellers under (a) the
Sellers' Agreements (other than the Labor Agreements) and the Transferable
Permits associated with the Purchased Assets in accordance with the terms
thereof, (b) the contracts, leases and other agreements entered into by the
Sellers with respect to the Purchased Assets which would be required to be
disclosed on Schedule 5.15(a) but for the exception provided in clause
(iii) of Section 5.15(a) of this Agreement, in accordance with the terms
thereof, and (c) the contracts, leases and other agreements entered into
by the Sellers with respect to the Purchased Assets after the date hereof
consistent with the terms of this Agreement; except in each case, to the
extent such liabilities and obligations, but for a breach or default by the
Sellers, would have been paid, performed or otherwise discharged on or
prior to the Closing Date or to the extent the same arise out of any such
breach or default or out of any event which after the giving of notice
would constitute a default;
(2) except in respect of any of the liabilities or obligations
described in Section 2.4, any liability, obligation or responsibility under
or related to former, current or future Environmental Laws or the common
law, whether such liability or obligation or responsibility is known or
unknown, contingent or accrued, arising as a result of or in connection
with (a) any violation or alleged violation of any Environmental Law after
the Closing Date, with respect to the ownership or operation of the
Purchased Assets; (b) compliance with applicable Environmental Laws after
the Closing Date with respect to the ownership or operation of the
Purchased Assets; (c) loss of life, injury to persons or property or damage
to natural resources caused (or allegedly caused) by the presence or
Release of Hazardous Substances at, on, in, under, or migrating from the
Purchased Assets after the Closing Date, including, but not limited to,
Hazardous Substances -13-
contained in building materials at the Purchased Assets or in the soil,
surface water, sediments, groundwater, landfill cells, or in other
environmental media at the Purchased Assets; (d) loss of life, injury to
persons or property or damage to natural resources caused (or allegedly
caused) by the off-site disposal, storage, transportation, discharge,
Release, recycling, or the arrangement for such activities, of Hazardous
Substances, after the Closing Date, in connection with the ownership or
operation of the Purchased Assets; (e) the investigation and/or remediation
of Hazardous Substances that are present or have been Released at, on, in,
under, or migrating from the Purchased Assets after the Closing Date,
including, but not limited to, Hazardous Substances contained in building
materials at the Purchased Assets or in the soil, surface water, sediments,
groundwater, landfill cells, or in other environmental media at the
Purchased Assets; (f) the investigation and/or remediation of Hazardous
Substances that are disposed, stored, transported, discharged, Released,
recycled, or the arrangement of such activities, after the Closing Date,
in connection with the ownership or operation of the Purchased Assets, at
any off-site location; and (g) any violation or alleged violation of
Environmental Law, and any loss of life, injury to persons or property or
damage to natural resources caused (or allegedly caused) by (i) acts by the
Buyer or its designee or their respective employees, invitees or agents
at any of the Purchased Assets on or after the date of this Agreement and
prior to the Closing Date; (ii) acts or omissions by a party other than a
Seller or its employees, invitees or agents at any of the Purchased Assets
after the Closing Date which cause a condition not in violation of an
Environmental Law or not in need of remediation under an Environmental Law
on the Closing Date to be in violation of such Environmental Law or in need
of remediation under such Environmental Law (including, without limitation,
the Release or destabilization of Hazardous Substances which are in a
stable or contained state and are in compliance with all applicable
Environmental Laws on the Closing Date); or (iii) acts or omissions by a
party other than a Seller or its employees, invitees or agents at any of
the Purchased Assets after the Closing Date that exacerbate or aggravate
any condition in violation of an Environmental Law or in need of
remediation under an Environmental Law on the Closing Date, to the extent
of any such exacerbation or aggravation; provided, however, that the mere
discovery by the Buyer of a condition in violation of an Environmental
Law or in need of remediation under an Environmental Law on the Closing
Date (including, without limitation, the discovery of a Hazardous Substance
in violation of an Environmental Law or in need of remediation under an
Environmental Law), in and of itself and without any other act or omission
by the Buyer, shall not be included in this subclause (g);
(3) all liabilities and obligations associated with the Purchased
Assets in respect of Taxes for which the Buyer is liable pursuant to
Section 3.5;
(4) any liabilities and obligations associated with the Purchased
Assets for which the Buyer has indemnified the Sellers pursuant to Section
9.1;
(5) all liabilities and obligations with respect to the Employees of
either of the Sellers to be employed at the Purchased Assets after the
Closing Date for which the Buyer is responsible pursuant to Section 7.10;
and -14-
(6) with respect to the Purchased Assets, any Tax that may be imposed
by any state or local government on the ownership, sale, operation or use
of the Purchased Assets for any period after the Closing Date.
(b) All of the foregoing liabilities and obligations to be assumed by the
Buyer or its designee under Section 2.3(a) (excluding any Excluded Liabilities)
are referred to herein as the "Assumed Obligations." It is understood and
agreed that nothing in this Section 2.3 shall constitute a waiver or release of
any claims arising out of the contractual relationships between the Sellers and
the Buyer or its designee.
2.4 Excluded Liabilities. Except as otherwise specifically provided in
this Agreement, neither the Buyer nor its designee shall assume or be obligated
to pay, perform, or otherwise discharge any of the following liabilities or
obligations:
(1) any liabilities or obligations of the Sellers in respect of any
Excluded Assets or other assets of the Sellers which are not Purchased
Assets;
(2) any liabilities or obligations of the Sellers in respect of Taxes
for any period on or before the Closing Date;
(3) any liability, obligation or responsibility under or related to
former, current or future Environmental Laws or the common law, whether
such liability or obligation or responsibility is known or unknown,
contingent or accrued, arising as a result of or in connection with (a) any
violation or alleged violation by either of the Sellers of any
environmental Law, on or before the Closing Date, arising from the use,
operation, or maintenance of the Purchased Assets by the Sellers; (b)
compliance by either of the Sellers with applicable Environmental Laws on
or before the Closing Date arising from the use, operation, or maintenance
of the Purchased Assets by the Sellers; (c) loss of life, injury to persons
or property or damage to natural resources caused (or allegedly caused) by
the presence, due to or resulting from any act or omission of either of the
Sellers, or Release by either of the Sellers of Hazardous Substances at,
on, in, under, adjacent to or migrating from the Purchased Assets on or
before the Closing Date, including, but not limited to, Hazardous
Substances contained in building materials at or adjacent to the Purchased
Assets or in the soil, surface water, sediments, groundwater, landfill
cells, or in other environmental media at the Purchased Assets; (d) loss
of life, injury to persons or property or damage to natural resources
caused (or allegedly caused) by the off-site disposal, storage,
transportation, discharge, Release, recycling, or the arrangement for such
activities, of Hazardous Substances, by either of the Sellers on or before
the Closing Date, in connection with the ownership or operation of the
Purchased Assets; (e) the investigation and/or remediation by either of the
Sellers of Hazardous Substances that are present or have been Released on
or before the Closing Date at, on, in, under, adjacent to or migrating from
the Purchased Assets, including, but not limited to, Hazardous Substances
contained in building materials at the Purchased Assets or in the soil,
surface water, sediments, groundwater, landfill cells or in other
environmental media at or adjacent to the Purchased Assets; (f) the
investigation and/or remediation by either of the Sellers of Hazardous
Substances that are disposed, stored, transported, discharged,
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Released, recycled, or the arrangement of such activities, on or before the
Closing Date, in connection with the ownership or operation of the
Purchased Assets, at any off-site location; or (g) any of the circumstances
described in subclauses (a) through (f) above if committed, done, or caused
by, or due to or resulting from any act or omission of, any party other
than the Sellers (other than the Buyer or its designee or their respective
employees, invitees or agents) if the Sellers have knowledge thereof
(notwithstanding the Buyer's knowledge thereof) on or prior to the Closing
Date; the Sellers agree and acknowledge that the Excluded Liabilities
described in this Section 2.4(3) shall include, without limitation, the
liabilities disclosed in Schedule 5.11, as amended from time to time
pursuant to Section 7.9, and any liabilities of the nature described in
subclauses (a) through (g) above discovered by the Buyer in accordance with
this Agreement and disclosed to the Sellers prior to the Closing Date,
other than any of the foregoing that was committed, done or caused by or
due to or resulting from any act of the Buyer or its employees, invitees
or agents;
(4) any liabilities, obligations or responsibilities relating to the
following, provided, however, that the Buyer or its designee may have
responsibility therefor under an Easement, an Interconnection Agreement,
the Continuing Site Agreement or otherwise than as an Assumed Obligation:
(a) the property, equipment or machinery retained by either Seller and kept
within the switchyards and substations for which the Sellers will retain
an Easement, (b) the transmission lines delineated in the Easements or (c)
any of Sellers' operations on, or usage of, the Easements, including,
without limitation, liabilities, obligations or responsibilities arising
as a result of or in connection with (1) any violation or alleged violation
by either of the Sellers of any Environmental Law or (2) loss of life,
injury to persons or property or damage to natural resources;
(5) any liabilities or obligations required to be accrued by the
Sellers in accordance with generally accepted accounting principles and the
FERC Uniform System of Accounts on or before the Closing Date with respect
to liabilities related to the Purchased Assets;
(6) any liabilities or obligations (a) relating to any claim, action,
suit or proceeding pending against either of the Sellers as of the Closing
Date, notwithstanding the disclosure thereof in any Schedule, or any
subsequent claim, action, suit or proceeding arising out of or relating to
such pending matters, (b) resulting from any act or omission of either of
the Sellers occurring on or prior to the Closing Date, (c) resulting from
the use, operation, or maintenance of the Purchased Assets by either
of the Sellers on or prior to the Closing Date, or (d) resulting from
property damage or personal injuries (including death) arising in
connection with the use, operation, or maintenance of the Purchased Assets
by either of the Sellers on or prior to the Closing Date;
(7) any fines or penalties imposed by a governmental agency resulting
from (A) an investigation or proceeding pending on or prior to the Closing
Date or (B) illegal acts, willful misconduct or gross negligence of the
Sellers prior to the Closing Date;
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(8) any payment obligations of the Sellers for goods delivered or
services rendered prior to the Closing;
(9) any liabilities or obligations imposed upon, assumed or retained
by the Sellers or any of their Affiliates pursuant to any of the Closing
Documents;
(10) any liabilities, obligations or responsibilities relating to any
Benefit Plan (as defined in Section 5.13(a) hereof), or to any "employee
pension benefit plan", as defined in Section 3(2) of ERISA, or to any
"pension plan", as defined in Section 1(1) of the Pension Benefits Act,
whether or not terminated, established, maintained or contributed to by any
of the Sellers or any of their ERISA Affiliates at any time or to which any
of the Sellers or any of their ERISA Affiliates are or have been obligated
to contribute to at any time ("ERISA Affiliate Plan"); including any
liability (A) to the Pension Benefit Guaranty Corporation under Title IV
of ERISA; (B) relating to a multiemployer plan; (C) with respect to
non-compliance with COBRA or HIPAA; (D) with respect to noncompliance with
any other applicable provision of the Code, ERISA, or the Pension Benefits
Act or any other applicable laws; or (E) with respect to any suit,
proceeding or claim which is brought against the Buyer with respect to any
Benefit Plan or ERISA Affiliate Plan, against any Benefit Plan or ERISA
Affiliate Plan, or against any fiduciary or former fiduciary of any such
Benefit Plan or ERISA Affiliate Plan; and
(11) any liabilities, obligations or responsibilities relating to the
employment or termination of employment by the Sellers of any individual
(including, but not limited to, any employee of the Sellers), except as
expressly assumed by the Buyer pursuant to Section 7.10.
All such liabilities and obligations not being assumed pursuant to this
Section 2.4 are herein called the "Excluded Liabilities".
The parties agree and acknowledge that the Sellers shall be entitled
exclusively to control, at Sellers' sole cost and expense, any litigation,
administrative or regulatory proceeding, and any investigation or remediation
activities (including without limitation any environmental mitigation or
remediation activities), arising out of or related to any Excluded Liabilities,
and the Buyer agrees promptly to notify the Sellers of the institution or
commencement of any of the foregoing if and when Buyer obtains knowledge
thereof, and to cooperate fully, at Sellers' sole cost and expense, with the
Sellers in connection therewith; provided, that all such remediation activities
conducted after the Closing Date shall be coordinated with the Buyer and
conducted in a manner as not to interfere unreasonably with Buyer's activities
at the Purchased Assets (including, without limitation, Buyer's operation and
maintenance of the Purchased Assets).
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ARTICLE III
PURCHASE PRICE
3.1 Purchase Price. The purchase price for the Purchased Assets shall be
an amount equal to the sum of (a) $37,425,000, and (b) the Adjustment Amount
(collectively, the "Purchase Price").
3.2 Purchase Price Adjustment.
(a) Within ten (10) Business Days after the Closing, the Sellers shall
prepare and deliver to the Buyer a statement (the "Adjustment Statement") which
reflects (i) the net book value, as reflected on the books of the Sellers as of
the Closing Date of all fuel inventory (FERC account no. 151) used at or in
connection with the Purchased Assets except the Wyman Station (the "Inventory
Adjustment Amount"), and (ii) the Maintenance and Capital Expenditures Amount.
The Inventory Adjustment Amount and the Maintenance and Capital Expenditures
Amount for the Closing are referred to collectively as the "Adjustment Amount."
The Inventory Adjustment Amount will be based on a fuel inventory survey
conducted within five days prior to the Closing Date consistent with current
inventory procedures of the Sellers (the "Inventory Survey"). The Sellers will
permit an employee, or representative, of the Buyer to observe the Inventory
Survey. The Adjustment Statement shall be prepared using the same generally
accepted accounting principles, policies and methods as the Sellers have
historically used in connection with the calculation of the items reflected on
such Adjustment Statement. The Buyer agrees to cooperate with the Sellers in
connection with the preparation of the Adjustment Statement and related
information, and shall provide to the Sellers such books, records and
information as may be reasonably requested from time to time.
(b) Within ten (10) Business Days after the Buyer's receipt of the
Adjustment Statement, the Buyer shall pay to MPS on behalf of the Sellers an
amount equal to the Adjustment Amount.
(c) The Purchase Price reflects Buyer's intent to use the diesel
generating facilities that are included within the Caribou Station on a regular
basis. Nevertheless, the permit that governs the discharge of cooling water
from those diesel generating facilities includes limits that inhibit such use
during periods of low water flow and warm weather. MPS agrees that, unless MPS
is able, prior to the Closing Date, to obtain modifications to such permit that
would allow Buyer to use such facilities without such an inhibition, such
modifications to be reasonably satisfactory to Buyer, then the Purchase Price
shall be reduced by One Hundred Thousand Dollars ($100,000).
3.3 Allocation of Purchase Price and Assumed Obligations. The Buyer and
the Sellers shall use their good faith best efforts to agree upon an allocation
among the Purchased Assets of the sum of the Purchase Price and the Assumed
Obligations consistent with Section 1060 of the Code and the Treasury
Regulations thereunder within 180 days after the date of this Agreement but in
no event less than 30 days prior to the Closing. The Buyer and the Sellers may
jointly agree to obtain the services of an independent engineer or appraiser
(the "Independent
-18-
Appraiser") to assist the parties in determining the fair value of the Purchased
Assets for purposes of such allocation. If such an appraisal is made, both the
Buyer and the Sellers agree to accept the Independent Appraiser's determination
of the fair value of the Purchased Assets. The parties shall jointly select the
Independent Appraiser. The cost of the appraisal shall be borne equally by the
Buyer and the Sellers. Each of the Buyer and the Sellers agrees to file
Internal Revenue Service Form 8594, and all federal, state, local and foreign
Tax Returns, in accordance with such agreed allocation. Each of the Buyer and
the Sellers shall report the transactions contemplated by the Agreement for
federal and provincial Income Tax and all other tax purposes in a manner
consistent with the allocation determined pursuant to this Section 3.3. Each
of the Buyer and the Sellers agrees to provide the other promptly with any other
information required to complete Form 8594. Each of the Buyer and the Sellers
shall notify and provide the other with reasonable assistance in the event of
an examination, audit or other proceeding regarding the agreed upon allocation
of the Purchase Price and the Assumed Obligations hereunder.
3.4 HST Election. The Buyer and the Sellers agree to execute jointly
in the statutorily prescribed form, and the Buyer will file within the time
required by subsection 167(1.1) of the Excise Tax Act (Canada), an election
under subsection 167(1) of the Excise Tax Act (Canada) that no HST be payable
with respect to the purchase and sale of the Canadian Assets hereunder.
3.5 Proration.
(a) The Buyer and the Sellers agree that all of the items normally
prorated, including those listed below, relating to the business and operation
of the Purchased Assets will be prorated as of the Closing Date, with the
Sellers liable to the extent such items relate to any time period prior to and
on the Closing Date, and the Buyer liable to the extent such items relate to
periods subsequent to the Closing Date:
(1) personal property, real estate, occupancy, sewerage and
water Taxes, assessments and other charges, if any, on or with respect to
the business and operation of the Purchased Assets;
(2) rent, Taxes and all other items payable under any of the
Sellers' Agreements assigned to and assumed by the Buyer hereunder which
are associated with the Purchased Assets;
(3) any permit, license, registration, compliance, or assurance
fees or other fees with respect to any Transferable Permit associated with
the Purchased Assets;
(4) sewer rents and charges for water, telephone, electricity
and other utilities; and
(5) rent under any leases of real or personal property included
in the Purchased Assets, including the leases described in Schedule 5.9.
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(b) In connection with the prorations referred to in clause (a) above, in
the event that actual figures are not available at the Closing Date, the
proration shall be based upon the actual Taxes or fees for the preceding year
(or appropriate period) for which actual Taxes or fees are available and such
Taxes or fees shall be reprorated upon request of either the Sellers, on one
hand, or the Buyer, on the other hand, made within sixty (60) days after the
date that the actual amounts become available. The Sellers and the Buyer agree
to furnish each other with such documents and other records as may be reasonably
requested in order to confirm all adjustment and proration calculations made
pursuant to this Section 3.5.
ARTICLE IV
THE CLOSING
4.1 Time and Place of Closing. Upon the terms and subject to the
satisfaction of the conditions contained in Article VIII of this Agreement (the
"Conditions"), the closing of the sale of the Purchased Assets contemplated by
this Agreement (the "Closing") will take place at the offices of Verrill & Dana,
LLP, One Portland Square, Portland, Maine 04112 at 10:00 A.M. (local time) on
such Business Day as the parties may agree, which date is as soon as
practicable, but no later than fifteen (15) Business Days following the date on
which all of the Conditions have been satisfied or waived; or at such other
place or time as the parties may agree. The date and time at which the Closing
actually occurs is hereinafter referred to as the "Closing Date."
4.2 Payment of Purchase Price.
(a) Upon the terms and subject to the satisfaction of the conditions
contained in this Agreement, in consideration of the aforesaid sale, assignment,
conveyance, transfer and delivery of the Purchased Assets, the Buyer will pay
or cause to be paid to the Sellers, as MPS may direct, at the Closing an amount
in United States dollars equal to $37,425,000, by wire transfer of immediately
available funds or by such other means as are agreed upon by the Sellers and the
Buyer.
(b) The Buyer shall pay the Adjustment Amount in accordance with Section
3.2.
4.3 Deliveries by the Sellers. At the Closing, the Sellers will deliver
the following to the Buyer:
(a) One or more Bills of Sale, duly executed by the appropriate Seller for
the personal property included in the Purchased Assets;
(b) All consents, waivers or approvals obtained by the Seller with respect
to the Purchased Assets, the transfer of any Transferable Permit related to the
Purchased Assets, or the consummation of the transactions connected to the sale
of the Purchased Assets, contemplated by this Agreement, to the extent
specifically required hereunder;
(c) Opinions of counsel and certificates (as contemplated by Section 8.2)
with respect to the Purchased Assets;
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(d) For the conveyance of the U.S. Real Property, one or more quit-claim
with covenant deeds to the Buyer or its designee, reserving the applicable
Easements, or, with respect to the Flo's Inn Station, an Easement in favor of
Buyer or its designee, in each case duly executed and acknowledged by the
appropriate Seller and in recordable form, together with a certificate of Maine
residency of MPS sufficient to relieve Buyer, its designee and their
representatives of any Maine withholding obligation relating to the sale of the
U.S. Real Property;
(e) For the conveyance of the Canadian Real Property, one or more deeds
to the Buyer or its designee utilizing Form A13 as prescribed by the Standard
Forms of Conveyances Act (New Brunswick, Canada) duly executed and acknowledged
by the appropriate Seller;
(f) The Continuing Site Agreement, the Buy-Back Agreement, and the
Interconnection Agreements, each duly executed by MPS;
(g) All Permits and Environmental Permits transferable to the Buyer or its
designee pursuant to this Agreement;
(h) All releases necessary to terminate and discharge any Encumbrances
(other than Permitted Encumbrances) on the Purchased Assets;
(i) Appropriate assignments necessary to transfer to the Buyer or its
designee all contracts and other intangible assets included in the Purchased
Assets;
(j) Originals of all books and records included in the Purchased Assets;
(k) All such other instruments of assignment or conveyance as shall, in
the reasonable opinion of the Buyer and its counsel, be necessary to transfer
to the Buyer or its designee the Purchased Assets, in accordance with this
Agreement and, where necessary or desirable, in recordable form;
(l) A copy of the resolutions of the Board of Directors of each of the
Sellers authorizing and approving this Agreement and each of the Closing
Documents to which it is a party and the consummation of the transactions
contemplated hereby and thereby, in each case certified by the secretary of the
respective Seller;
(m) A copy of the articles of incorporation and by-laws (or equivalent
charter documents) of each of the Sellers, in each case certified by the
secretary of the respective Seller, and a copy of the articles of incorporation
(or equivalent charter document(s)) of each Seller certified by the Secretary
of State of Maine, with respect to MPS, and the director of Corporate and Trust
Affairs of New Brunswick, Canada, with respect to MNB;
(n) Certificates by the secretary of each Seller as to the incumbency of
each person executing any Closing Document on behalf of such Seller;
(o) Such affidavits and, to the extent consistent with and not in addition
to the terms hereof, indemnities reasonably requested by Buyer's title insurance
company; and
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(p) Such other agreements, documents, instruments and writings as are
required to be delivered by the Sellers at or prior to the Closing Date pursuant
to this Agreement or otherwise required in connection herewith.
In addition to the foregoing, MPS shall, on the Closing Date or on such other
date after the Closing Date as the parties may specify in writing, dismantle,
crate and deliver, at Buyer's sole cost and expense, the Purchased Assets
constituting personal property at the Houlton Station, to a location designated
by Buyer in writing not less than thirty (30) days prior to the Closing Date.
4.4 Deliveries by the Buyer. At the Closing, the Buyer will deliver the
following to the Sellers:
(a) The portion of the Purchase Price referred to in Section 4.2(a), by
wire transfer of immediately available U.S. funds, or by such other means as are
agreed upon by the Sellers and the Buyer;
(b) Opinions of counsel and certificates (as contemplated by Section 8.3)
with respect to the Purchased Assets;
(c) The Instruments of Assumption with respect to the Assumed Obligations,
duly executed by the Buyer or its designee;
(d) All such other instruments of assumption as shall, in the reasonable
opinion of the Sellers and its counsel, be necessary for the Buyer or its
designee to assume the Assumed Obligations related to the Purchased Assets in
accordance with this Agreement;
(e) A copy of the resolutions of the Board of Directors (or similar
governing board) of each of the Buyer and its designees authorizing and
approving this Agreement and each of the Closing Documents to which it is a
party and the consummation of the transactions contemplated hereby and thereby,
certified by the secretary (or similar officer) of the Buyer or its designee,
as the case may be;
(f) A copy of the articles of incorporation and by-laws (or equivalent
charter documents) of each of the Buyer and its designees, certified by its
secretary (or similar officer), and a copy of the articles of incorporation (or
equivalent charter documents) of each of the Buyer and its designees, certified
by the Wisconsin Department of Financial Institutions, or by the similar
authority in any jurisdiction of organization other than Wisconsin;
(g) A certificate by the secretary (or similar officer), of each of the
Buyer, and its designees, as to the incumbency of each person executing any
Closing Document on behalf of Buyer or its designee, as the case may be; and
(h) Such other agreements, documents, instruments and writings as are
required to be delivered by the Buyer, or its designee, at or prior to the
Closing Date pursuant to this Agreement or otherwise required in connection
herewith.
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ARTICLE V
REPRESENTATIONS AND WARRANTIES OF THE SELLERS
Each of the Sellers, for itself, represents and warrants to the Buyer as
follows, as of the date hereof and on and as of the Closing Date:
5.1 Organization; Qualification. MPS is a corporation duly organized,
validly existing and in good standing under the laws of the State of Maine and
has all requisite corporate power and authority to own, lease, and operate its
properties and to carry on its business as is now being conducted. MNB is a
corporation duly organized, validly existing and in good standing under the
laws of the Province of New Brunswick, Canada and has all requisite corporate
power and authority to own, lease, and operate its properties and to carry on
its business as is now being conducted. MPS owns directly 100% of the issued
and outstanding capital stock of MNB. The Sellers are duly qualified or
licensed to do business as foreign corporations and are in good standing in each
jurisdiction in which the property owned, leased or operated by them or the
nature of the business conducted by them makes such qualification necessary,
except in each case in those jurisdictions where the failure to be so duly
qualified or licensed and in good standing would not create a Material Adverse
Effect. The states, provinces, and other jurisdictions in which the Sellers are
qualified or licensed to do business are listed in Schedule 5.1.
5.2 Authority Relative to this Agreement. Each of the Sellers has full
corporate power and authority to execute and deliver this Agreement and each of
the other Closing Documents to which it is a party and to consummate the
transactions contemplated hereby and thereby. The execution and delivery by
each Seller of this Agreement and each of the other Closing Documents to which
it is a party and the consummation of the transactions contemplated hereby and
thereby have been duly and validly authorized by the Board of Directors of MPS
and by the Board of Directors of MNB and its sole shareholder, and no other
corporate proceedings on the part of either Seller are necessary to authorize
this Agreement or any of the other Closing Documents to which it is a party or
to consummate the transactions contemplated hereby or thereby. No notice to,
meeting of, action by, or approval of the shareholders of MPS is necessary to
authorize the execution and delivery of this Agreement or any of the other
Closing Documents to which MPS is a party, or to consummate the transactions
contemplated hereby or thereby. No preferred stock of MPS is issued and
outstanding. Each of this Agreement and the other Closing Documents to which
either Seller is a party has been duly and validly executed and delivered by
such Seller, and assuming that each of this Agreement and such other Closing
Documents constitutes a valid and binding agreement of the Buyer, subject to the
receipt of the Sellers Required Regulatory Approvals and the Buyer Required
Regulatory Approvals, constitutes a valid and binding agreement of such Seller
enforceable against such Seller in accordance with its terms, except that such
enforceability may be limited by applicable bankruptcy, insolvency, moratorium
or other similar laws affecting or relating to enforcement of creditors' rights
generally and by general principles of equity.
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5.3 Consents and Approvals; No Violation.
(a) Except as set forth in Schedule 5.3, and other than obtaining the
Sellers Required Regulatory Approvals and the Buyer Required Regulatory
Approvals, neither the execution and delivery of this Agreement and the other
Closing Documents by the Sellers nor the consummation of the transactions
contemplated hereby or thereby (including, without limitation, the sale by the
Sellers of the Purchased Assets pursuant to this Agreement and the other Closing
Documents) will (i) conflict with or result in any breach of any provision of
the respective organizational documents or bylaws of the Sellers, (ii) require
any consent, approval, authorization or permit of, or filing with or
notification to, any governmental or regulatory authority, except (x) where the
failure to obtain such consent, approval, authorization or permit, or to make
such filing or notification, would not, individually or in the aggregate, create
a Material Adverse Effect or (y) for those requirements which become applicable
to the Sellers as a result of the specific regulatory status of the Buyer (or
any of its Affiliates) or as a result of any other facts that specifically
relate to the business or activities in which the Buyer (or any of its
Affiliates) is or proposes to be engaged; (iii) result in or constitute a
default (or an event which, with notice or lapse of time, or both, would
constitute a default), or give rise to any right of termination, cancellation
or acceleration, or result in the creation of any Encumbrance upon any of the
assets of the Sellers, under any of the terms, conditions or provisions of any
note, bond, mortgage, indenture, license, agreement or other instrument or
obligation to which either of the Sellers is a party or by which either of the
Sellers, or any of the Purchased Assets may be bound, except for such defaults
(or events which, with notice or lapse of time, or both, would constitute a
default), or rights of termination, cancellation or acceleration as to which
requisite waivers or consents have been obtained or which, in the aggregate,
would not, individually or in the aggregate, create a Material Adverse Effect;
or (iv) violate any order, writ, injunction, decree, statute, rule or regulation
applicable to either of the Sellers, or any of their assets, which violation,
individually or in the aggregate, would create a Material Adverse Effect.
(b) Except as set forth in Schedule 5.3 and except for (i) any required
approvals under the Federal Power Act, (ii) (A) notice by MPS to, and an order
by, the PUC approving the transactions contemplated by this Agreement, (B) the
approval by the Lieutenant-Governor in Council of New Brunswick of the
transactions involving MNB and its assets contemplated by this Agreement, (iii)
the approval, if required, of the SEC pursuant to the Holding Company Act, (iv)
the approval, if required, of the National Energy Board of Canada and the Board
of Commissioners of Public Utilities of the Province of New Brunswick, Canada
and (v) the approval, if required, of the State of Maine with respect to the
inclusion within the Purchased Assets of any rights, franchises, privileges or
similar assets of the Sellers deriving from any private and special laws or
other legislative grant or charter (the filings and approvals referred to in
clauses (i) through (v) are collectively referred to as the "Sellers Required
Regulatory Approvals"), no declaration, filing or registration with, or notice
to, or authorization, consent or approval of any governmental or regulatory body
or authority is necessary for the consummation by the Sellers of the
transactions contemplated under this Agreement and the other Closing Documents,
other than such declarations, filings, registrations, notices, authorizations,
consents or approvals which, if not obtained or made, will not, individually or
in the aggregate, create a Material Adverse Effect.
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5.4 Reports. Since January 1, 1994, the Sellers have filed or caused to
be filed with the SEC, the applicable state, provincial or local utility
commissions or regulatory bodies, or the FERC, as the case may be, all material
forms, statements, reports and documents (including all exhibits, amendments and
supplements thereto) required to be filed by the Sellers with respect to the
business and operations of the Sellers as it relates to the Purchased Assets
under each of the Securities Act, the Exchange Act, the applicable State and
provincial public utility laws, the Federal Power Act (United States), the
Holding Company Act (United States), the Business Corporations Act (New Bruns-
wick, Canada) and the National Energy Board Act (Canada), and the respective
rules and regulations thereunder, all of which complied in all material respects
with all applicable requirements of the appropriate act and the rules and reg-
ulations thereunder in effect on the date each such report was filed, and there
were no material misstatements or omissions contained in such reports as of the
respective dates thereof, in each case with respect to the Purchased Assets.
5.5 Financial Statements. The Sellers have made available to the Buyer
their balance sheets, as of March 31, 1997 and March 31, 1998, and the related
statements of income and cash flows for the years then ended (including the
notes related thereto). Such balance sheets (including the related statements
of income and cash flows and the related notes thereto) are referred to herein
as the "Sellers Balance Sheets". Each of the Sellers Balance Sheets is complete
and accurate, has been prepared in accordance with generally accepted accounting
principles applied on a consistent basis, except as otherwise noted therein, and
presents fairly, as of the date thereof, the financial position of such Seller
in conformity with generally accepted accounting principles applied on a
consistent basis, except as otherwise noted therein.
5.6 Undisclosed Liabilities. Except as set forth in Schedule 5.6, the
Sellers have no liabilities or obligations relating to the Purchased Assets, the
operation or maintenance of the Purchased Assets, or the business of the Sellers
in connection therewith, secured or unsecured (whether absolute, accrued,
contingent or otherwise, and whether due or to become due), which are not
accrued or reserved against in the Sellers Balance Sheets as of March 31, 1998
(the "Sellers Recent Balance Sheets") or disclosed in the notes thereto in
accordance with generally accepted accounting principles, except commercial
liabilities and obligations incurred since the date of the Sellers Recent
Balance Sheets in the ordinary course of business and consistent with past
practice and none of which has or will have a Material Adverse Effect. Except
as set forth in Schedule 5.6, the Sellers have no knowledge of any basis for the
assertion against the Sellers or any successor in interest thereto of any
liability or obligation relating to the Purchased Assets, the operation of the
Purchased Assets, or the business of the Sellers in connection therewith, and
to the knowledge of the Sellers there are no circumstances, conditions,
happenings, events or arrangements, contractual or otherwise, which may give
rise to any such liabilities or obligations, except commercial liabilities and
obligations incurred in the ordinary course of business consistent with past
practice.
5.7 Absence of Certain Changes or Events. Except (i) as set forth in
Schedule 5.7, or in the reports, schedules, registration statements and
definitive proxy statements filed by MPS with the SEC and (ii) as otherwise
contemplated by this Agreement, since the date of the Sellers Recent Balance
Sheets there has not been (a) any Material Adverse Effect; (b) any damage,
destruction or casualty loss, whether covered by insurance or not, which,
individually or in the
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aggregate, create a Material Adverse Effect; (c) any entry into any agreement,
commitment or transaction (including, without limitation, any borrowing, capital
expenditure or capital financing, any amendment or termination of any contract
or agreement, or any waiver of material rights) by the Sellers with respect to
the Purchased Assets, except agreements, commitments or transactions in the
ordinary course of business consistent with past practice that individually or
in the aggregate are not material to the Purchased Assets, the operation or
maintenance of the Purchased Assets, or the business of the Sellers in
connection therewith, and except agreements, commitments or transactions that
do not extend beyond the Closing Date with respect to the Purchased Assets; (d)
any change by the Sellers, with respect to the Purchased Assets, in accounting
methods, principles or practices except as required or permitted by generally
accepted accounting principles; (e) any increase in the compensation, salaries
or wages payable to or to become payable to any Employee (including, without
limitation, any increase or change pursuant to any bonus, pension, profit
sharing, retirement or other plan or commitment), or any bonus or other employee
benefit granted, made or accrued to or for the benefit of any Employee, other
than in the ordinary course of business consistent with past practice; (f) any
loan or advance (other than advances to Employees in the ordinary course of
business for travel and entertainment in accordance with past practice) to any
Person including, but not limited to, any Employee; or (g) any sale, lease, or
other transfer or disposition of any properties or assets of the Sellers related
to the Purchased Assets, the operation or maintenance of the Purchased Assets,
or the business of the Sellers in connection with the Purchased Assets, other
than transfers or dispositions in the ordinary course of business consistent
with past practice, and other than dispositions of obsolete or unusable
property, that individually or in the aggregate are not material to the
Purchased Assets, the operation or maintenance of the Purchased Assets or the
business of the Sellers in connection therewith.
5.8 Title to and Condition of Properties.
(a) Marketable Title. Except as set forth in Schedule 5.8(a) and except
for other Permitted Encumbrances, the Sellers have and at Closing Buyer or its
designee will receive (i) good and marketable title to all of the Real Estate,
free and clear of all Encumbrances and (ii) good and valid title to all of the
personal property included within the Purchased Assets, free and clear of all
Encumbrances. The foregoing representation with respect to title to the Real
Estate shall expire upon consummation of the Closing and thereafter Buyer shall,
with respect to such matters, rely upon the covenants set forth in the deeds for
the Real Estate and upon title insurance with respect to the U.S. Real Property,
and similar third-party assurances with respect to the Canadian Real Property.
Except for the Sellers Required Regulatory Approvals and the Buyer Required
Regulatory Approvals, none of the Purchased Assets are subject to any
restrictions with respect to the transferability thereof.
(b) Condition. Except as set forth in Schedule 5.8(b), the tangible
assets at each station, taken as a whole (real and personal), constituting
Purchased Assets (i) are in good operating and usable condition and repair, free
from any defects (except ordinary wear and tear, in light of their respective
ages and historical usages, and except such minor defects as do not interfere
with the use thereof in the conduct of the normal operation and maintenance of
the Purchased Assets); and (ii) have been maintained consistent with the
standards generally followed in the industry. The Buyer acknowledges that an
item is not defective merely because it breaks or
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otherwise fails after a reasonable amount of time has passed or after it has
provided a reasonable amount of usage.
(c) Real Estate. Schedule 5.8(c) sets forth all real property owned,
leased, used or occupied by Sellers and included in the Purchased Assets (the
"Real Estate"), including a description of all land, exhibits indicating the
location thereof, and all Encumbrances, easements or rights of way of record
(or, if not of record, of which Sellers have notice or knowledge) granted on or
appurtenant to or otherwise affecting such Real Estate, the zoning classifica-
tion thereof, and all plants, buildings or other structures located thereon.
Except with respect to the Millinocket Facility, which has no deeded access
rights but depends upon custom and usage as described in Schedule 5.8(c), no
fact or condition exists which would prohibit or adversely affect the ordinary
rights of access to and from the Real Estate from and to the existing highways
and roads and there is no pending or threatened restriction or denial, govern-
mental or otherwise, upon such ingress or egress. Except as set forth on
Schedule 5.8(c), Sellers' occupation and use of the Real Estate is in material
compliance with all applicable laws and regulations. Except as set forth on
Schedule 5.8(c), there is not (i) any claim of adverse possession or
prescriptive rights involving any of the Real Estate, (ii) any structure located
on any Real Estate which encroaches on or over the boundaries of neighboring or
adjacent properties or (iii) any structure of any other party which encroaches
on or over the boundaries of any of such Real Estate. Except as indicated in
Schedule 5.8(c), none of the Real Estate is located in a flood plain, flood
hazard area, wetland or lakeshore erosion area within the meaning of any
applicable order, decree, statute, rule, or regulation. No public improvements
have been commenced and to the knowledge of the Sellers none are planned which
in either case may result in special assessments against any of the Real Estate
or otherwise create a Material Adverse Effect. No portion of any of the Real
Estate has been used as a landfill or for storage or landfill of hazardous or
toxic materials. Except as set forth on Schedule 5.8(c), the Sellers have no
knowledge of any (i) planned or proposed increase in assessed valuations of any
Real Estate, (ii) order, writ, injunction, or decree requiring repair,
alteration, or correction of any existing condition affecting any Real Estate
or the systems or improvements thereat, (iii) condition or defect which could
give rise to an order of the sort referred to in "(ii)" above, or (iv)
underground storage tanks, or any structural, mechanical, or other defects of
material significance affecting any Real Estate or the systems or improvements
thereat (including, but not limited to, inadequacy for normal use of mechanical
systems or disposal or water systems at or serving the Real Estate).
(d) No Certified Survey Map Required. No certified survey map or other
state, municipal, or other governmental approval regarding the division,
platting, or mapping of real estate is required as a prerequisite to the
conveyance by the Sellers to Buyer (or as a prerequisite to the recording of any
conveyance document) of any Real Estate pursuant to the terms hereof.
5.9 Leases. Schedule 5.9 lists, as of the date of this Agreement, all
real property leases under which the Sellers are a lessee or lessor and which
(x) relate to the Purchased Assets, the operation or maintenance of the
Purchased Assets, or the business of the Sellers in connection therewith and
(y) (i) provide for annual payments of more than $1,000 or (ii) are material to
the operation or condition (financial or otherwise) of the Purchased Assets or
the business of the Sellers in connection therewith. Except as set forth in
Schedule 5.9, all such leases are valid, binding and enforceable in accordance
with their terms, and are in full force and effect; there are
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no existing material defaults by the Sellers or, to the Sellers' knowledge, any
other party thereunder; and no event has occurred which (whether with or without
notice, lapse of time or both) would constitute a material default by the
Sellers or, to the Sellers' knowledge, any other party thereunder, or would
cause the acceleration of any of the Sellers' obligations thereunder or result
in the creation of any Encumbrance on any of the Purchased Assets, or would give
rise to an automatic termination, or the right of discretionary termination,
thereof.
5.10 Insurance. Except as set forth in Schedule 5.10, all material
policies of fire, liability, worker's compensation and other forms of insurance
owned or held by the Sellers (including self insurance) with respect to the
Purchased Assets, the operation or maintenance of the Purchased Assets, or the
business of the Sellers in connection therewith, are in full force and effect,
all premiums with respect thereto covering all periods up to and including the
date as of which this representation is being made have been paid (other than
retroactive premiums which may be payable with respect to comprehensive general
liability and worker's compensation insurance policies), and no notice of
cancellation or termination has been received with respect to any such policy
which was not replaced on substantially similar terms prior to the date of such
cancellation. Except as set forth on Schedule 5.10, there is no claim by the
Sellers pending under any such policies as to which coverage has been
questioned, denied or disputed by the underwriters of such policies, and the
Sellers know of no basis for denial of any claim under any such policy. Except
as set forth on Schedule 5.10, neither of the Sellers has received any written
notice from or on behalf of any insurance carrier issuing any such policy that
insurance rates therefor will hereafter be substantially increased (except to
the extent that insurance rates may be increased for all similarly situated
risks) or that there will hereafter be a cancellation or an increase in a
deductible (or an increase in premiums in order to maintain an existing
deductible) or nonrenewal of any such policy. Except as described in Schedule
5.10, the Sellers have not been refused any insurance with respect to the
Purchased Assets, the operation or maintenance of the Purchased Assets, or the
business of the Sellers in connection therewith, nor has their coverage been
limited by any insurance carrier to which they have applied for any such
insurance or with which they have carried insurance during the last twelve
months.
5.11 Environmental Matters. Except as disclosed in Schedule 5.11 or in any
public filing by MPS pursuant to the Securities Act or the Exchange Act:
(a) The Sellers hold, and are in compliance with, all of the permits,
licenses and governmental authorizations identified in Schedule 5.11, which are
all of the permits, licenses and governmental authorizations required for the
Sellers to own, operate, maintain, and engage in business related to the
Purchased Assets under applicable Environmental Laws (collectively, the
"Environmental Permits"), and the Sellers are otherwise in compliance with all
applicable Environmental Laws with respect to the Purchased Assets, the
operation or maintenance of the Purchased Assets, or the business of the Sellers
in connection with the Purchased Assets, except for such failures to hold or
comply with required Environmental Permits, or such failures to be in compliance
with applicable Environmental Laws which, individually or in the aggregate, are
not reasonably likely to create a Material Adverse Effect.
(b) The Sellers have not received any written request for information or
been notified that they are a potentially responsible party under CERCLA or any
other Environmental Law, or
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are potentially subject to any judgment, rule, order, writ, injunction, or
decree of any court, governmental or regulatory authority under the Clean
Environment Act (New Brunswick, Canada) or the Clean Water Act (New Brunswick,
Canada), and there are no claims, actions, proceedings or investigations pending
or, to the knowledge of Sellers, threatened against Sellers before any court,
governmental or regulatory authority or body acting in an adjudicative capacity
relating in any way to any Environmental Laws.
(c) The Sellers have not entered into or agreed to any consent decree or
order, and are not subject to any outstanding judgment, decree, or judicial
order relating to compliance with any Environmental Law or to investigation or
cleanup of Hazardous Substances under any Environmental Law. The representations
and warranties made in this Section 5.11 are the Sellers' exclusive
representations and warranties relating to environmental matters.
5.12 Labor Matters. All collective bargaining agreements to which the
Sellers are a party or are subject and which relate to the operation or
maintenance of the Purchased Assets or the business of the Sellers in connection
therewith are identified in Schedule 7.10(b). Solely (in each of the following
clauses (a) through (f)) with respect to the operation or maintenance of the
Purchased Assets or the business of the Sellers in connection therewith, except
to the extent set forth in Schedule 5.12 and except for such matters as will
not, individually or in the aggregate, create a Material Adverse Effect (a) the
Sellers are in compliance with all applicable laws respecting employment and
employment practices, terms and conditions of employment and wages and hours,
and are not engaged in any unfair labor practice; (b) there is no unfair labor
practice charge or complaint pending or, to the knowledge of the Sellers,
threatened against the Sellers; (c) there is no labor strike, dispute, slowdown
or stoppage actually pending or, to the Sellers' knowledge threatened against
or affecting the Sellers; (d) no question concerning representation has been
raised or, to the knowledge of Sellers, is threatened respecting the employees
of the Sellers; (e) no arbitration proceeding arising out of or under collective
bargaining agreements is pending against the Sellers; and (f) there are no
administrative charges or court complaints against the Sellers concerning
alleged employment discrimination or other employment related matters pending
or, to the knowledge of Sellers, threatened before the U.S. Equal Employment
Opportunity Commission, any administrative tribunals in New Brunswick governing
human rights matters, or any governmental or regulatory body or authority.
5.13 ERISA; Benefit Plans.
(a) Schedule 5.13(a) lists (i) all "employee pension benefit plans", as
defined in Section 3(2) of ERISA, and all "pension plans", as defined in Section
1(1) of the Pension Benefits Act, including multiemployer plans (of which none
exist), established, maintained or contributed to (or previously maintained or
contributed to within the last six fiscal years) by the Sellers or any of their
ERISA Affiliates for the benefit of current or former employees employed at the
Purchased Assets, for the operation or maintenance of the Purchased Assets, or
in connection with the business of Sellers relating to the Purchased Assets
("Pension Plans"); (ii) all "employee welfare benefit plans", as defined in
Section 3(1) of ERISA, established, maintained or contributed to (or previously
maintained or contributed to within the last six fiscal years) by the Sellers
or any of their ERISA Affiliates for the benefit of current or former employees
employed at the Purchased Assets, for the operation or maintenance of the
Purchased Assets, or in connection with the
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business of Sellers relating to the Purchased Assets ("Welfare Plans"); and
(iii) all bonus, compensation or other fringe benefit plans, programs, and
arrangements established, maintained or contributed to (or previously
maintained or contributed to within the last six fiscal years) by the Sellers
or any of their ERISA Affiliates for the benefit of current or former employees
employed at the Purchased Assets, for the operation or maintenance of the
Purchased Assets, or in connection with the business of Sellers relating to the
Purchased Assets, without regard to the coverage of any such plan, program
or arrangement by ERISA or any provision of the Code. The plans, programs and
arrangements listed on Schedule 5.13(a) are collectively referred to herein as
the "Benefit Plans". Accurate and complete copies of all Benefit Plans and all
material employee communications of general application related to such Benefit
Plans have been made available to the Buyer.
(b) Except as set forth in Schedule 5.13(b):
(1) No Pension Plan and no ERISA Affiliate Plan has ever
incurred an "accumulated funding deficiency", as defined in Section 302 of
ERISA and Section 412 of the Code, whether or not waived, nor incurred a
"solvency deficiency", as defined in Section 2 of the General Regulation
- Pension Benefits Act, NB Reg. 91-195, as amended;
(2) None of the Sellers nor any ERISA Affiliate has incurred any
liability to the Pension Benefit Guaranty Corporation under Sections 4062,
4063, 4064 or 4069 of ERISA in connection with any Pension Plan that is
subject to Title IV of ERISA, and none of the Purchased Assets is subject
or potentially subject to a lien under Section 4068 of ERISA;
(3) No Pension Plan and no ERISA Affiliate Plan, and no trust
created under any such plan, has been terminated or has commenced voluntary
or involuntary termination proceedings under Sections 4041 or 4042 of ERISA
or has experienced a "reportable event" as defined in Section 4043 of ERISA
or has been wound up or commenced voluntary or involuntary wind up
proceedings under Sections 60 or 61 of the Pension Benefits Act; and
(4) The Internal Revenue Service has issued a letter for each
Pension Plan that is intended to be qualified determining that such plan
is exempt from United States Federal Income Tax under Sections 401(a) and
501(a) of the Code. To the Sellers' knowledge, there has been no
occurrence since the date of any such determination letter that has
adversely affected (or might reasonably be expected to adversely affect)
such qualification and each Pension Plan in form and in operation is in
compliance in all respects with all applicable provisions of ERISA and the
Code. The Minister of National Revenue has registered each Pension Plan
provided for employees of the Sellers employed in New Brunswick, Canada,
pursuant to the provisions of the Income Tax Act (Canada). Each Pension
Plan in form and operation is in material compliance with applicable
provisions of the Pension Benefits Act and the Income Tax Act (Canada).
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(5) All contributions or payments required to be made as of or
before the Closing Date by the Sellers to, for, or in respect of the
Benefit Plans, the IBEW Agreements, and the Pension Benefits Act have been
made.
(c) None of the Sellers nor any ERISA Affiliate has engaged in any
transaction to avoid or evade liability within the meaning of Section 4069(b)
of ERISA. No Benefit Plan and no ERISA Affiliate Plan is a "multiemployer
plan", as defined in Section 4001(a)(3) of ERISA or Section 1(1) of the Pension
Benefits Act, or a single-employer plan under multiple controlled groups, within
the meaning of Sections 4063-64 of ERISA.
(d) Each Welfare Plan has been maintained in accordance with the
requirements of ERISA and other applicable law. In addition, each of the
Sellers that maintains a "group health plan" within the meaning of Section
5000(b)(1) of the Code has materially complied in good faith with the applicable
requirements of COBRA and HIPAA.
(e) Except as set forth in Schedule 5.13(b), none of the Sellers, any
ERISA Affiliate, any Benefit Plan that is subject to ERISA, Section 4975 of the
Code, or the Pension Benefits Act, or any fiduciary, party in interest,
disqualified person, affiliate or related person, with respect to any Benefit
Plan has engaged or caused any such Benefit Plan to engage in any transaction
prohibited by Section 406 or Section 407(a) of ERISA or Section 4975 of the
Code, unless an appropriate exemption or exemptions have been obtained therefor
under Section 408 of ERISA and Section 4975 of the Code, or prohibited by
Section 44 of the General Regulation - Pension Benefits Act, NB Reg. 91-195, as
amended.
(f) With the exception of routine claims for benefits, including
associated appeals and disputes of denied claims, arising in the ordinary course
of administration of the Benefit Plans, no material claims, assessments,
investigations, or proceedings in arbitration or litigation, or by or before the
Superintendent of Pensions of the Province of New Brunswick or the Labour and
Employment Board (New Brunswick), relating to or arising under any Benefit Plan
are pending or, to the knowledge of Sellers, threatened against any Seller, any
ERISA Affiliate, any Benefit Plan, or any trust or other funding arrangement
created under or established as part of any Benefit Plan, or against any
trustee, fiduciary, custodian, administrator, or any other Person, and the
Sellers have no basis to anticipate that any such claim or claims exist.
(g) Except as set forth on Schedule 5.13(a), Seller does not maintain,
provide or contribute to a post-retirement welfare benefit plan (including,
without limitation, post-retirement medical benefits for or on behalf of current
or former employees employed at the Purchased Assets, for the operation and
maintenance of the Purchased Assets, or in connection with the business of
Sellers relating to the Purchased Assets).
5.14 Condemnation. Except as set forth in Schedule 5.14, neither the whole
nor any part of the Real Estate or any other real property or rights leased,
used or occupied by the Sellers in connection with the ownership or operation
of the Purchased Assets is subject to any outstanding order by any public
authority to be sold, or any pending suit for condemnation or other taking by
any public authority, and to the knowledge of Sellers, no such condemnation or
other taking has been threatened.
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5.15 Certain Contracts and Arrangements.
(a) Except (i) as listed in Schedule 5.15(a) or 7.10(b), (ii) for
contracts, agreements, personal property leases, commitments, understandings or
instruments under which all rights, benefits, duties and obligations, contingent
or otherwise, of any party or beneficiary will expire on or prior to the Closing
Date, and (iii) for agreements with suppliers entered into in the ordinary
course of business that in each case (x) do not provide for annual payments of
more than $1,000 and (y) are not material to the operation or condition
(financial or otherwise) of the Purchased Assets or the business of the Sellers
in connection therewith, the Sellers are not a party to any written contract
(including, without limitation, any employment contract), agreement, personal
property lease, commitment, understanding or instrument relating to the business
or operations of the Purchased Assets. Accurate and complete copies of all
Sellers' Agreements have been made available to Buyer.
(b) Except as disclosed in Schedule 5.15(b), each Sellers' Agreement (i)
constitutes a valid and binding obligation of MPS or MNB, and to the knowledge
of the Sellers constitutes a valid and binding obligation of the other parties
thereto, (ii) is in full force and effect, and no notice of termination has been
delivered by any party thereunder, and (iii) may be transferred to the Buyer
pursuant to this Agreement and will continue in full force and effect
thereafter, in each case without breaching the terms thereof or resulting in the
forfeiture or impairment of any rights thereunder. Without limitation of the
foregoing, (i) no consent of The Perth-Andover Electric Light Commission is
required for the valid transfer and assignment to the Buyer of the Agreement
between MNB and The Perth-Andover Electric Light Commission dated December 7,
1993 (which became effective on January 2, 1995), and (ii) no consent of any
other Owner of the Wyman Station is required for the valid transfer and assign-
ment to the Buyer of MPS's right, title and interest in and to the Wyman Agree-
ments and such transfer and assignment will not give rise to any right of first
refusal in favor of any other such Owner under any of the Wyman Agreements.
(c) Except as set forth in Schedule 5.15(c), there is not, under any of
the Sellers' Agreements, any default or event which, with notice or lapse of
time or both, would (i) constitute a default on the part of any of the parties
thereto, except such events of default and other events as to which requisite
waivers or consents have been obtained or which would not, individually or in
the aggregate, create a Material Adverse Effect, (ii) would give rise to an
automatic termination, or the right of discretionary termination, thereof, or
(iii) would cause the acceleration of any of the Sellers' obligations or result
in the creation of any Encumbrance on any of the Purchased Assets.
5.16 Legal Proceedings, etc. Except as set forth in Schedule 5.16 or in
any public filing made by MPS pursuant to the Securities Act or the Exchange
Act, there are no claims, actions, proceedings or investigations pending or, to
the knowledge of Sellers, threatened against or relating to the Sellers before
any court, governmental or regulatory authority or body acting in an
adjudicative capacity, which, if adversely determined, individually or in the
aggregate, would create a Material Adverse Effect. Except as set forth in
Schedule 5.16 or in any public filing made by MPS pursuant to the Securities Act
or the Exchange Act, the Sellers are not subject to any outstanding judgment,
rule, order, writ, injunction or decree of any court, governmental or
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regulatory authority which, individually or in the aggregate, would create a
Material Adverse Effect.
5.17 Permits. All permits, licenses, franchises and other governmental
authorizations, consents and approvals, other than the Environmental Permits,
necessary to own or otherwise utilize, operate or maintain, or engage in the
business of the Sellers in connection with, the Purchased Assets as presently
conducted, are identified in Schedule 5.17 (collectively, the "Required
Permits"). Except as set forth in Schedule 5.17, the Sellers have not received
any written notification that they are, or in the future may be considered to
be, in violation of any of the Required Permits, or any law, statute, order,
rule, regulation, ordinance or judgment of any governmental or regulatory body
or authority applicable to any Required Permits, except for notifications of
violations which would not, individually or in the aggregate, create a Material
Adverse Effect. The Sellers are in compliance with all Required Permits, laws,
statutes, orders, rules, regulations, ordinances, or judgments of any
governmental or regulatory body or authority applicable to it, except for
violations which, individually or in the aggregate, do not create a Material
Adverse Effect.
5.18 Regulation as a Utility. MPS is an exempt public utility holding
company within the meaning of the Holding Company Act. MPS is subject to
regulation in the United States as a public utility or public service company
(or similar designation other than as an Exempt Wholesale Generator within the
meaning of the Holding Company Act) only by FERC and the PUC; MPS is not
subject to regulation in Canada. MNB is subject to regulation in Canada as a
public utility only by the New Brunswick Board of Commissioners of Public
Utilities, and is subject to regulation by the National Energy Board with
respect to the international export of electricity and the construction and
operation of international power transmission lines and infrastructure; MNB is
not subject to regulation in the United States.
5.19 Taxes. With respect to the Purchased Assets and the business of the
Sellers associated with the Purchased Assets, (i) all Tax Returns required to
be filed other than those Tax Returns the failure of which to file would not
create a Material Adverse Effect have been filed and, in each case when filed,
were true, complete and correct in all material respects, and (ii) all material
Taxes shown to be due on such Tax Returns have been paid in full. Except as set
forth in Schedule 5.19, no notice of deficiency or assessment has been received
from any taxing authority with respect to liabilities for Taxes of the Sellers
in respect of the Purchased Assets (nor to the knowledge of Sellers has any such
taxing authority threatened to issue such notice or assessment), which have not
been fully paid or finally settled, and any such deficiency shown in such
Schedule 5.19 is being contested in good faith through appropriate proceedings.
Except as set forth in Schedule 5.19, there are no outstanding agreements or
waivers extending the applicable statutory periods of limitation for Taxes
associated with the Purchased Assets for any period. Schedule 5.19 sets forth
the taxing jurisdictions in which the Sellers own assets or conduct business
that require a notification to a taxing authority of the transactions
contemplated by this Agreement, if the failure to make such notification, or
obtain Tax clearances in connection therewith, would either require the Buyer
to withhold any portion of the Purchase Price or would subject Buyer to any
liability for any Taxes of the Sellers.
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5.20 Sufficiency of Purchased Assets. The Purchased Assets constitute all
of Sellers' generation assets, other than MPS's Power Purchase Agreement with
Wheelabrator-Sherman Energy Company (successor to Signal-Sherman Energy Company,
assignee of Sherman Power Company), and the real property that is included
within the Houlton Station, and, together with the Continuing Site Agreement
and the Interconnection Agreements, are sufficient to allow Buyer, after the
Closing, if it has obtained all necessary governmental approvals, to deliver the
output of such generation assets to MPS's transmission system at the respective
interconnection points specified in the Interconnection Agreements. Without
limiting the foregoing, the Purchased Assets shall include all of MPS's right,
title and interest under any private and special laws of Maine that relate to
the Purchased Assets. As of the Closing Date, the Purchased Assets will meet
the standards with respect thereto contained in the Interconnection Agreements
and the Continuing Site Agreement. Sellers have reviewed, and are reviewing,
their business operations and assets with respect to Year 2000 compliance and,
to the best of the Sellers' knowledge, the Purchased Assets do not include any
material assets that are not Year 2000 compliant.
5.21 Buyer's Knowledge. The Sellers shall be deemed to have disclosed
hereunder, as if they had set it forth on a schedule hereto, any facts and
circumstances known to Buyer as of the date of this Agreement, whether known to
Buyer through independent means or through review of Sellers' facilities and
records, even if such matter is not listed on any Schedule attached hereto.
EXCEPT FOR THE REPRESENTATIONS AND WARRANTIES EXPRESSLY SET FORTH IN THIS
ARTICLE V, THE PURCHASED ASSETS ARE BEING SOLD AND TRANSFERRED "AS IS, WHERE
IS," AND THE SELLERS ARE NOT MAKING ANY OTHER REPRESENTATIONS OR WARRANTIES,
WRITTEN OR ORAL, STATUTORY, EXPRESS OR IMPLIED, CONCERNING SUCH PURCHASED
ASSETS, INCLUDING, IN PARTICULAR, ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR
A PARTICULAR PURPOSE, ALL OF WHICH ARE HEREBY EXPRESSLY EXCLUDED AND DISCLAIMED.
ARTICLE VI
REPRESENTATIONS AND WARRANTIES OF THE BUYER
The Buyer represents and warrants to the Sellers as follows as of the date
hereof and on and as of the Closing Date:
6.1 Organization. The Buyer is a corporation duly organized, validly
existing and in good standing under the laws of the State of Wisconsin and has
all requisite corporate power and authority to own, lease and operate its
properties and to carry on its business as is now being conducted.
6.2 Authority Relative to this Agreement. The Buyer has full corporate
power and authority to execute and deliver this Agreement and each of the other
Closing Documents to which it is a party and to consummate the transactions
contemplated hereby and thereby. The execution and delivery by Buyer of this
Agreement and each of the other Closing Documents to which it is a party and the
consummation of the transactions contemplated hereby and thereby
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have been duly and validly authorized by the Board of Directors of the Buyer and
no other corporate proceedings on the part of the Buyer are necessary to
authorize this Agreement or to consummate the transactions contemplated hereby.
Each of this Agreement and the other Closing Documents to which Buyer is a party
has been duly and validly executed and delivered by the Buyer, and assuming that
each of this Agreement and such other Closing Documents constitutes a valid and
binding agreement of the Sellers, subject to the receipt of the Buyer Required
Regulatory Approvals and the Sellers Required Regulatory Approvals, constitutes
a valid and binding agreement of the Buyer, enforceable against the Buyer in
accordance with its terms, except that such enforceability may be limited by
applicable bankruptcy, insolvency, moratorium or other similar laws affecting
or relating to enforcement of creditors' rights generally or general principles
of equity.
6.3 Consents and Approvals; No Violation.
(a) Except as set forth in Schedule 6.3, and other than obtaining the
Buyer Required Regulatory Approvals and the Sellers Required Regulatory
Approvals, neither the execution and delivery of this Agreement and the other
Closing Documents by the Buyer nor the consummation of the transactions
contemplated hereby or thereby (including, without limitation, the purchase by
the Buyer or its designee of the Purchased Assets and the assumption by the
Buyer or its designee of the Assumed Obligations pursuant to this Agreement and
the other Closing Documents) will (i) conflict with or result in any breach of
any provision of the Certificate of Incorporation or Bylaws (or other similar
governing documents) of the Buyer, (ii) require any consent, approval,
authorization or permit of, or filing with or notification to, any governmental
or regulatory authority, or (iii) result in a default (or give rise to any right
of termination, cancellation or acceleration) under any of the terms, conditions
or provisions of any note, bond, mortgage, indenture, agreement, lease or other
instrument or obligation to which the Buyer or any of its subsidiaries is a
party or by which any of their respective assets may be bound, except for such
defaults (or rights of termination, cancellation or acceleration) as to which
requisite waivers or consents have been obtained.
(b) Except as set forth in Schedule 6.3 and except for (i) qualification
of the Buyer and/or each of its designees as an exempt wholesale generator under
the Energy Policy Act of 1992, without restriction, including no restriction on
sales to Affiliates, (ii) authorization to sell power under Section 205 of the
Federal Power Act, (iii) approval by FERC, under Part I of the Federal Power
Act, of the transfer of FERC project licenses related to, and necessary to
operate, the Purchased Assets as currently operated, and approval by FERC of
market-based rates for Buyer or its designees (or, alternatively, a disclaimer
by FERC of jurisdiction under the Federal Power Act as to wholesale sales and
either the approval by the State of Maine of market-based rates or a disclaimer
by the State of Maine of jurisdiction over wholesale sales by Buyer or its
designees), (iv) approval by the SEC pursuant to Section 9(a)(1) of the Holding
Company Act if WPS Resources Corporation is required to register as a public
utility holding company under the Holding Company Act prior to the Closing Date,
(v) approval of the Department of Energy, Economic Regulatory Administration to
export electricity to Canada from the United States, (vi) approval of the
Superintendent of Pensions of the Province of New Brunswick of the establishment
of any pension plan by Buyer or its designee in respect of its Canadian
employees, (vii) any PUC approval or approval by the Lieutenant-Governor in
Council of New Brunswick or
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the approval of the Board of Commissioners of Public Utilities of the Province
of New Brunswick necessary for the Sellers to transfer any Purchased Assets in
Maine or New Brunswick and for the Buyer or its designee to purchase the
Purchased Assets or assume the Assumed Obligations in Maine or New Brunswick,
and (viii) any necessary approval of the National Energy Board to export
electricity from Canada to the United States and to operate international power
transmission infrastructure as currently carried on in the conduct of the
business of MNB in connection with the Purchased Assets (the filings and
approvals referred to in clauses (i) through (viii) are collectively referred
to as the "Buyer Required Regulatory Approvals"), no declaration, filing or
registration with, or notice to, or authorization, consent or approval of any
governmental or regulatory body or authority is necessary for the consummation
by the Buyer of the transactions contemplated hereby.
6.4 Regulation as a Utility. The Buyer is not subject to regulation as
a public utility or public service company (or similar designation other than
as an Exempt Wholesale Generator within the meaning of the Holding Company Act)
by the United States, any State of the United States, any foreign country or
any municipality or any political subdivision of the foregoing.
6.5 Disclosure. Buyer has reviewed all materials identified on Schedule
6.5 in the form provided by Sellers to Buyer, and has had the opportunity to ask
questions of Sellers' officers and employees and to undertake such review as it
has deemed necessary or advisable with respect to the Purchased Assets, the
Assumed Obligations and Sellers' operations.
ARTICLE VII
COVENANTS OF THE PARTIES
7.1 Conduct of Business Relating to the Purchased Assets.
(a) Except as described in Schedule 7.1, during the period from the date
of this Agreement to the Closing Date, the Sellers will operate the Purchased
Assets and related businesses in the usual, regular and ordinary course
consistent with good industry practice and shall use all commercially reasonable
efforts to preserve intact the Purchased Assets and the businesses related
thereto, and endeavor to preserve the goodwill and relationships with customers,
suppliers and others having business dealings with them. Without limiting the
generality of the foregoing, and, except as contemplated in this Agreement or
as described in Schedule 7.1, prior to the Closing Date, without the prior
written consent of the Buyer, the Sellers will not with respect to the Purchased
Assets and related businesses, except in each case in the ordinary course of the
Sellers' businesses:
(1) except for (1) Permitted Encumbrances and (2) indebtedness
constituting Excluded Liabilities that does not create an Encumbrance on
the Purchased Assets that will continue beyond the Closing Date, create,
incur, assume or suffer to exist any indebtedness for borrowed money
(including obligations in respect of capital leases);
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(2) make any material change in the levels of fuel inventory and
stores inventory customarily maintained by the Sellers with respect to the
Purchased Assets, other than consistent with good industry practice;
(3) sell, lease (as lessor), transfer or otherwise dispose of,
any of the Purchased Assets, other than assets used, consumed or replaced
in the ordinary course of business consistent with good industry practice;
(4) terminate, extend or otherwise materially amend any of the
Sellers' Agreements, any other contracts, agreements, personal property
leases, commitments, understandings, instruments, or real property leases
to the extent any such extension or amendment would require such item to
be disclosed on Schedule 5.9 or 5.15(a), or waive any material default by,
or release, settle or compromise any material claim against, any other
party thereto;
(5) enter into, terminate, extend or otherwise amend any real
or personal property Tax agreement, treaty or settlement;
(6) execute, enter into, terminate or otherwise amend any of the
Required Permits or the Environmental Permits, other than routine renewals
or non-material modifications or amendments; and
(7) with respect to the Purchased Assets and related businesses,
(x) amend in a material, adverse way, or cancel any liability or casualty
insurance policies related thereto, (y) compromise, settle, withdraw,
release or abate any material claims made or accruing thereunder or (z)
fail to maintain by self insurance or with financially responsible
insurance companies insurance in such amounts and against such risks and
losses as are customary for such assets and businesses.
(b) Notwithstanding anything in Section 7.1(a) to the contrary, the
Sellers may, in their sole discretion, make (i) Maintenance Expenditures and
Capital Expenditures (provided that the Buyer shall not be liable for any such
expenditures in excess of the Maintenance and Capital Expenditures Amount), and
(ii) at the Sellers' expense, such other maintenance and capital expenditures
as the Sellers deem necessary.
(c) A committee comprised of one Person designated by the Sellers and one
Person designated by the Buyer, and such additional Persons as may be appointed
by the Persons originally appointed to such committee (the "Transition
Committee") will be established as soon after execution of this Agreement as is
practicable to examine the business issues affecting the Purchased Assets and
related businesses of the Sellers after the date hereof, giving emphasis to
cooperation between the Buyer and the Sellers after the execution of this
Agreement. From time to time, the Transition Committee shall report its
findings to the senior management of each of MPS and the Buyer.
(d) Between the date of this Agreement and the Closing Date, in the
interest of cooperation between the Sellers and the Buyer and to permit informed
action by the Buyer
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regarding its rights pursuant to Section 7.1(a) to grant, consent or to waive
prohibitions or limitations under Section 7.1(a), the parties agree as follows.
At the sole responsibility and expense of the Buyer, the Sellers will permit
designated employees ("Observers") of the Buyer to observe all operations of the
Sellers that relate to the Purchased Assets and related businesses, and to
observe discussions with third parties relating solely to the Purchased Assets
(not including discussions with legal counsel or accountants), and such
observation will be permitted on a cooperative basis in the presence of
personnel of the Sellers but not restricted to the normal business hours of the
Sellers; provided, however, that such Observers and their actions shall not
unreasonably interfere with the operation of the Sellers' business. The Buyer's
Observers may recommend or suggest actions be taken or not be taken by the
Sellers; provided, however, that the Sellers will be under no obligation to
follow any such recommendations or suggestions and the Sellers shall be
entitled, subject to this Agreement, to conduct their business in accordance
with their own judgment and discretion. The Buyer's Observers shall have no
authority to bind or make agreements on behalf of the Sellers; to conduct
discussions with or make representations to third parties on behalf of the
Sellers; or to issue instructions to or direct or exercise authority over the
Sellers or any of the Sellers' officers, employees, advisors or agents.
7.2 Access to Information.
(a) Between the date of this Agreement and the Closing Date, the Sellers
will, during ordinary business hours and upon reasonable notice (i) give the
Buyer and the Buyer Representatives reasonable access to all books, records,
plants, offices and other facilities and properties constituting the Purchased
Assets or relating to the Assumed Obligations to which the Buyer is not denied
access by law; (ii) permit the Buyer to make such reasonable inspections thereof
as the Buyer may reasonably request; (iii) furnish the Buyer with such financial
and operating data and other information with respect to the Purchased Assets
or the Assumed Obligations as the Buyer may from time to time reasonably
request; (iv) furnish the Buyer a copy of each material report, schedule or
other document filed or received by them with respect to the Purchased Assets
or the Assumed Obligations with the SEC, PUC, DEP, FERC, the National Energy
Board, the Board of Commissioners of Public Utilities of the Province of New
Brunswick, or the Superintendent of Pensions of the Province of New Brunswick;
provided, however, that (A) any such investigation shall be conducted in such
a manner as not to interfere unreasonably with the operation of the Purchased
Assets, (B) the Sellers shall not be required to take any action which would
constitute a waiver of the attorney-client privilege and (C) the Sellers need
not supply the Buyer with any information which the Sellers are under a legal
obligation not to supply. Notwithstanding anything in this Section 7.2 to the
contrary, (i) the Sellers will only furnish or provide such access to
Transferring Employee Records and personnel and medical records as is permitted
or required by law, legal process or subpoena and (ii) the Buyer shall not have
the right to perform or conduct any environmental sampling or testing at, in,
on, or underneath the Purchased Assets, except as set forth on Schedule 7.2
hereof.
(b) All information furnished to or obtained by the Buyer and the Buyer's
Representatives pursuant to this Section 7.2 shall be subject to the provisions
of the Confidentiality Agreement and shall be treated as "Proprietary
Information" (as defined in the Confidentiality Agreement).
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(c) For a period of six years after the Closing Date, each party and their
representatives shall have reasonable access to all of the books and records of
the Purchased Assets, including all Transferring Employee Records or other
personnel and medical records permitted or required by law, legal process or
subpoena, in the possession of the other party or parties to the extent that
such access may reasonably be required by such party in connection with the
Assumed Obligations or the Excluded Liabilities, or other matters relating to
or affected by the operation of the Purchased Assets. Such access shall be
afforded by the party or parties in possession of such books and records upon
receipt of reasonable advance notice and during normal business hours. The
party or parties exercising this right of access shall be solely responsible for
any costs or expenses incurred by it or them pursuant to this Section 7.2(c).
If the party or parties in possession of such books and records shall desire to
dispose of any such books and records upon or prior to the expiration of such
six-year period, such party or parties shall, prior to such disposition, give
the other party or parties a reasonable opportunity at such other party's or
parties' expense, to segregate and remove such books and records as such other
party or parties may select.
(d) Notwithstanding the terms of the Confidentiality Agreement and Section
7.2(b) above, the parties agree that prior to the Closing the Buyer may reveal
or disclose Proprietary Information to any other Persons in connection with
financing, and risk management if reasonably necessary, of or with respect to
the Purchased Assets, and to such Persons with whom the Buyer expects it may
have business dealings regarding the Purchased Assets from and after the Closing
Date, and, to the extent that the Sellers consent (which consent shall not be
unreasonably withheld) to existing and potential customers and suppliers, in
each case only so long as such other parties enter into confidentiality agree-
ments in favor of MPS on terms satisfactory to MPS.
(e) Except as required by law, unless otherwise agreed to in writing by
the Buyer, for a period commencing on the Closing Date and terminating three
years after such date the Sellers shall keep (i) all Proprietary Information
confidential and not disclose or reveal any Proprietary Information to any
Person other than Sellers' Representatives who are actively and directly partic-
ipating in the transactions contemplated hereby or who otherwise need to know
the Proprietary Information for such purpose and to cause those Persons to
observe the terms of this Section 7.2(e) and (ii) not to use Proprietary Infor-
mation for any purpose other than consistent with the terms of this Agreement
and the other Closing Documents. The Sellers shall continue to hold all Pro-
prietary Information according to the same internal security procedures and with
the same degree of care regarding its secrecy and confidentiality as currently
applicable thereto. The Sellers shall notify the Buyer of any unauthorized dis-
closure to third parties that it discovers, and shall endeavor to prevent any
further such disclosures. The Sellers shall be responsible for any breach of
the terms of this Section 7.2(e) by the Sellers or the Sellers' Representa-
tives.
After the Closing Date, in the event that the Sellers are requested pur-
suant to, or required by, applicable law or regulation or by legal process to
disclose any Proprietary Information, or any other information concerning the
Purchased Assets, or the transactions contemplated hereby, the Sellers shall
provide the Buyer with prompt notice of such request or requirement in order to
enable the Buyer to seek an appropriate protective order or other remedy, to
consult with the Sellers with respect to taking steps to resist or narrow the
scope of such request or legal process, or to waive compliance, in whole or in
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part, with the terms of this Section 7.2(e). The Sellers agree not to oppose
any action by the Buyer to obtain a protective order or other appropriate remedy
after the Closing Date. In the event that no such protective order or other
remedy is obtained, or that the Buyer waives compliance with the terms of this
Section 7.2(e), the Sellers shall furnish only that portion of the Proprietary
Information which the Sellers are advised by counsel is legally required. In
any such event the Sellers shall use their reasonable best efforts to ensure
that all Proprietary Information and other information that is so disclosed will
be accorded confidential treatment.
(f) The parties agree that the Confidentiality Agreement will terminate,
without further act or evidence by the parties, upon consummation of the
Closing.
7.3 Expenses. Except to the extent specifically provided herein, whether
or not the transactions contemplated hereby are consummated, all costs and
expenses incurred in connection with this Agreement and the transactions
contemplated hereby shall be borne by the party incurring such costs and
expenses.
7.4 Further Assurances.
(a) Subject to the terms and conditions of this Agreement, each of the
parties hereto will use its best efforts to take, or cause to be taken, all
action, and to do, or cause to be done, all things necessary, proper or
advisable under applicable laws and regulations to consummate and make effective
the sale of the Purchased Assets pursuant to this Agreement, including without
limitation using its best efforts to ensure satisfaction of the conditions
precedent to each party's obligations hereunder. Notwithstanding anything in
the previous sentence to the contrary, the Sellers and the Buyer shall use their
commercially reasonable efforts to obtain all Permits and Environmental
Permits necessary for the Buyer to own, operate and maintain the Purchased
Assets and to deliver the output thereof to MPS's transmission system at the
respective interconnection points specified in the Interconnection Agreements.
Neither of the parties hereto will, without prior written consent of the other
party, take or fail to take any action, which would reasonably be expected to
prevent or materially impede, interfere with or delay the transactions
contemplated by this Agreement. From time to time after the date hereof,
without further consideration, the Sellers will, at their own expense, execute
and deliver such documents to the Buyer or its designee as the Buyer may
reasonably request in order to more effectively vest in the Buyer the Sellers'
title to the Purchased Assets subject only to Permitted Encumbrances. Without
limiting the foregoing, the Sellers shall cooperate with the Buyer in the
Buyer's efforts to cure or remove any defects or Encumbrances existing with
respect to the Real Estate that the Buyer reasonably deems objectionable;
provided, however, that in connection therewith the Sellers shall not be under
any obligation to initiate legal action or to incur expense other than reason-
able administrative and out-of-pocket expenses. From time to time after the
date hereof, the Buyer will, at its own expense, execute and deliver such eff-
documents to the Sellers as the Sellers may reasonably request in order to more
ectively consummate the sale of the Purchased Assets pursuant to this Agreement.
(b) To the extent that the Sellers' rights under any Sellers' Agreement
may not be assigned without the consent of another Person which consent has not
been obtained, this Agreement shall not constitute an agreement to assign the
same if an attempted assignment would
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constitute a breach thereof or be unlawful, and the Sellers, at their expense,
shall use their commercially reasonable efforts to obtain any such required
consents as promptly as possible. The Sellers and the Buyer agree that if any
consent to an assignment of any Sellers' Agreement shall not be obtained or if
any attempted assignment would be ineffective or would impair the Buyer's or its
designee's rights and obligations under the Sellers' Agreement in question so
that the Buyer or its designee would not in effect acquire the benefit of all
such rights and obligations, the Sellers, to the maximum extent permitted by law
and such Sellers' Agreement, shall after the Closing (assuming that the Buyer,
in its sole and absolute discretion, waives in writing the condition precedent
to Closing set forth in Section 8.2(k)), appoint the Buyer or its designee to
be the Sellers' representative and agent with respect to such Sellers' Agree-
ment, and the Sellers shall, to the maximum extent permitted by law and such
Sellers' Agreement, enter into such reasonable arrangements with the Buyer or
its designee as are necessary to provide the Buyer or its designee with the
benefits and obligations of such Sellers' Agreement. The Sellers and the Buyer
shall cooperate and shall each use their commercially reasonable efforts after
the Closing to obtain an assignment of such Sellers' Agreement to the Buyer or
its designee.
7.5 Public Statements. The parties shall consult with each other prior
to issuing any public announcement, statement or other disclosure with respect
to this Agreement or the transactions contemplated hereby and shall not issue
any such public announcement, statement or other disclosure prior to such
consultation, except as may be required by law and except that the parties may
make public announcements, statements or other disclosures with respect to this
Agreement and the transactions contemplated hereby to the extent and under the
circumstances in which the parties are expressly permitted by the Confident-
iality Agreement to make disclosures of "Proprietary Information" (as defined
in the Confidentiality Agreement).
7.6 Consents and Approvals; Financing.
(a) The Sellers and the Buyer agree that there is no need to file with the
Federal Trade Commission or the United States Department of Justice any
notifications under the HSR Act and the rules and regulations promulgated
thereunder with respect to the transactions contemplated hereby.
(b) The Sellers and the Buyer shall cooperate with each other and (i)
promptly prepare and file all necessary documentation, (ii) effect all necessary
applications, notices, petitions and filings and execute all agreements and
documents, (iii) use all commercially reasonable efforts to obtain the transfer
or reissuance to the Buyer of all necessary Transferable Permits, consents,
approvals and authorizations of all governmental bodies and (iv) use all
commercially reasonable efforts to obtain all necessary consents, approvals and
authorizations of all other parties, in the case of each of the foregoing
clauses (i), (ii), (iii) and (iv), necessary or advisable to consummate the
transactions contemplated by this Agreement (including, without limitation, the
Sellers Required Regulatory Approvals and the Buyer Required Regulatory
Approvals) or required by the terms of any note, bond, mortgage, indenture,
deed of trust, license, franchise, permit, concession, contract, lease or other
instrument to which the Sellers or the Buyer is a party or by which any of them
is bound. Each of the Sellers and the Buyer shall have the right to review in
advance all characterizations of the information relating to the transactions
contemplated by this
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Agreement which appear in any filing made in connection with the transactions
contemplated hereby.
(c) The Sellers and the Buyer shall cooperate with each other and promptly
prepare and file notifications with, and request Tax clearances from, state,
provincial and local taxing authorities in jurisdictions in which a portion of
the Purchase Price may be required to be withheld or in which the Buyer would
otherwise be liable for any Tax liabilities of the Sellers pursuant to such
state and local Tax law.
(d) Notwithstanding anything herein to the contrary, the Sellers shall use
all commercially reasonable efforts to assist Buyer in obtaining all third party
consents (including, without limitation, consents to the collateral assignment
in favor of the Buyer's lenders of contracts or agreements included in the
Purchased Assets), agreements, certificates, opinions, and other documents or
instruments reasonably requested by the Buyer's lenders in connection with the
financing, on a non- or limited recourse basis or otherwise, of Buyer's
acquisition of the Purchased Assets hereunder, all of which shall be at Buyer's
sole cost and expense to the extent that any such items are not otherwise
required of Sellers hereunder or under any of the Closing Documents. From time
to time after the date hereof, without further consideration, the Sellers will,
at their own expense, execute and/or deliver such consents (including, without
limitation, consents to the collateral assignment in favor of the Buyer's
lenders of the Closing Documents), agreements, certificates, opinions, and other
documents or instruments to the Buyer's lenders as the Buyer's lenders may
reasonably request in connection with the financing, on a non- or limited
recourse basis or otherwise, of Buyer's acquisition of the Purchased Assets
hereunder. Sellers acknowledge that Buyer intends to obtain financing, on a
non- or limited recourse basis or otherwise and on terms and conditions
acceptable to Buyer, of Buyer's acquisition of the Purchased Assets hereunder
and Buyer confirms that obtaining such financing is not a condition precedent
to its obligations hereunder.
7.7 Fees and Commissions. The Sellers and the Buyer each represent and
warrant to the other that no broker, finder or other Person is entitled to any
brokerage fees, commissions or finder's fees in connection with the transaction
contemplated hereby by reason of any action taken by the party making such
representation. The Sellers and the Buyer will pay to the other or otherwise
discharge, and will indemnify and hold the other harmless from and against, any
and all claims or liabilities for all brokerage fees, commissions and finder's
fees incurred by reason of any action taken by such party.
7.8 Tax Matters.
(a) All transfer and sales taxes incurred in connection with this
Agreement and the transactions contemplated hereby shall be borne by the
Sellers, other than Maine real estate transfer taxes which shall be paid equally
by Buyer and MPS, and MPS, at its own expense, will file, to the extent required
by applicable law, all necessary Tax Returns and other documentation with
respect to all such transfer or sales taxes, and, if required by applicable law,
the Buyer will join in the execution of any such Tax Returns or other
documentation. Prior to the Closing Date, MPS will provide to the Buyer, to the
extent possible, an appropriate certificate of no Tax
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incurred in connection with this Agreement and the transactions contemplated
hereby, from each applicable taxing authority.
(b) With respect to Taxes to be prorated in accordance with Section 3.5
of this Agreement only, the Buyer shall prepare and timely file all Tax Returns
required to be filed after the Closing with respect to the Purchased Assets, if
any, for the period in which such Taxes must be reported, and shall duly and
timely pay all such Taxes shown to be due on such Tax Returns. The Buyer's
preparation of any such Tax Returns shall be subject to the Sellers' approval,
which approval shall not be unreasonably withheld. The Buyer shall make such
Tax Returns available for the Sellers' review and approval no later than
fifteen (15) Business Days prior to the due date for filing such Tax Return.
Within ten (10) Business Days after receipt of such Tax Return, the Sellers
shall pay to the Buyer their proportionate share of the amount shown as due on
such Tax Return determined in accordance with Section 3.5 of this Agreement.
(c) Each of the Buyer and the Sellers shall provide the other with such
assistance as may reasonably be requested by the other party in connection with
the preparation of any Tax Return, any audit or other examination by any taxing
authority, or any judicial or administrative proceedings relating to liability
for Taxes, and each will retain and provide the requesting party with any
records or information which may be relevant to such return, audit or
examination, proceedings or determination. Any information obtained pursuant
to this Section 7.8(c) or pursuant to any other Section hereof providing for the
sharing of information or review of any Tax Return or other schedule relating
to Taxes shall be kept confidential by the parties hereto.
7.9 Supplements to Schedules. Prior to the Closing Date, the Sellers and
the Buyer shall supplement or amend the Schedules referenced in this Agreement
with respect to any matter relating to the subject matter thereof hereafter
arising which, if existing or occurring at the date of this Agreement, would
have been required to be set forth or described in such Schedules. No
supplement or amendment of any Schedule made pursuant to this Section shall be
deemed to cure any breach of, or expand or limit the scope of, or otherwise
modify or affect any representation or warranty made in this Agreement unless
the parties agree thereto in writing.
7.10 Employees.
(a) During the period beginning on the date of this Agreement and ending
on the Closing Date (the "Buyer's Window"), the Buyer or its designee may offer
employment, effective as of the Closing Date, to employees of the Sellers who
are presently employed principally in connection with the ownership, operation,
or maintenance of the Purchased Assets, and who are assigned to the departments
listed in Schedule 7.10(a) and listed individually in such Schedule 7.10(a) (all
such employees hereinafter referred to individually as an "Employee" and
collectively as "Employees"); provided, however, that if any such individual
ceases to be employed by either of the Sellers after the date hereof, Buyer or
its designee may offer employment during the Buyer's Window, effective as of the
Closing Date, to any individual or individuals who, in general, performs the
functions and duties of such departed individual (and any such replacement
individual or individuals, as the case may be, shall be deemed an "Employee" for
the purposes of this Section 7.10).
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All such offers of employment shall be made (i) in accordance with all
applicable laws and regulations, and (ii) for Employees represented by the
International Brotherhood of Electrical Workers ("IBEW"), in accordance with the
applicable IBEW Agreements (or any replacement or extension thereof as in
effect at such time). (Each person who becomes employed by the Buyer or its
designee as of the Closing Date pursuant to this Section 7.10 shall be referred
to herein as a "Transferred Employee.")
During the Buyer's Window, the Sellers will refrain from offering
post-Closing employment to any of the Employees without the prior consent of the
Buyer, other than those Employees who the Buyer indicates in writing it does not
intend to hire. Buyer shall in good faith notify Seller as soon as possible
regarding those employees who the Buyer does not intend to offer employment.
The Buyer shall not solicit, directly or indirectly, for employment any
employees of the Sellers at any time beginning on the date hereof and up to and
including the second anniversary of the Closing Date, other than offers to
Employees made during the Buyer's Window.
Subject to the provisions set forth below, the Sellers shall not, at any
time beginning at the end of the Buyer's Window and ending on the second
anniversary of the Closing Date, solicit, directly or indirectly, for employment
any Employee who accepted a position with the Buyer or its designee within the
Buyer's Window. In the event the Buyer or its designee decides to terminate the
employment of one or more of the Transferred Employees on or before 12 months
following the Closing Date, Buyer or its designee shall provide Sellers with at
least seventy-five (75) days advance written notice, following which Sellers
shall have the right to offer employment to any such affected Transferred
Employee, such employment to commence no sooner than the effective date of the
Transferred Employee's employment termination with Buyer or its designee, as the
case may be.
With respect to any Employee who does not receive an offer of employment
from the Buyer or its designee, the Sellers shall be responsible for providing
such Employees with any benefits under the Sellers' Employee Transition Plan,
which such Employees may be entitled to receive under the terms of said Plan.
If, for any reason, any Employee has received severance benefits under the
Sellers' Employee Transition Plan and is subsequently employed by Buyer at any
time on or before the one (1) year anniversary of the Closing Date, Buyer shall
reimburse the Sellers for the cost of any such severance benefits, whether such
severance benefits are provided in cash or in kind.
(b) Schedule 7.10(b) sets forth all of the collective bargaining
agreements, and amendments thereto, to which the Sellers are a party with the
IBEW in connection with the Purchased Assets (the "IBEW Agreements"). With
respect to Transferred Employees who are included in the collective bargaining
units covered by the IBEW Agreements (the "Transferred IBEW Employees"), as of
the Closing Date the Buyer or its designee will assume the IBEW Agreements as
they relate to Transferred IBEW Employees. The Buyer or its designee shall
comply with all applicable obligations under the IBEW Agreements and will accept
and fulfill all obligations under the IBEW Agreements, together with any
revisions and/or extensions thereto, including, but not limited to, the
obligation of Buyer or its designee to recognize the IBEW as the collective
bargaining agent for the Transferred IBEW Employees. Transferred IBEW Employees
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shall be given credit for prior service with the Sellers for all purposes under
the IBEW Agreements.
(c) For the period commencing on the Closing Date and ending December 31,
2001, the Buyer or its designee shall provide all Transferred Employees who
remain in its employ and who are not IBEW Employees ("Transferred Non-Union
Employees") with total salary, benefits and opportunities for bonuses which is,
in the aggregate, comparable to the total salary, benefits and opportunities for
bonuses provided to such Employees by the Sellers immediately prior to the
Closing Date. Nothing herein shall be deemed to guarantee a Transferred
Employee continued employment with the Buyer or its designee for any definite
period of time.
(d) As of the Closing Date, all Transferred Employees shall, except as
otherwise provided in this Section 7.10 or required by applicable law, cease to
participate in the Welfare Plans and shall commence to participate in the
employee welfare benefit plans, programs, and arrangements of the Buyer and its
Affiliates, without regard to the coverage of any such plan, program, or
arrangement by ERISA or any provision of the Code (the "Replacement Welfare
Plans") on at least the same terms and conditions as similarly situated
employees of the Buyer. The Buyer shall (i) waive or cause to be waived, except
to the extent that such waiver is precluded by applicable law, any waiting
period, probationary period, pre-existing condition exclusion, evidence of
insurability requirement, or similar condition with respect to Transferred
Employees under the Replacement Welfare Plans, other than, but only to the
extent of, any waiting period, probationary period, pre-existing condition
exclusion, evidence of insurability requirement, or similar condition that was
in effect with respect to any such Transferred Employee under a Welfare Plan of
the Seller and that had not been satisfied by such individual as of the Closing
Date, and (ii) provide each such Transferred Employee with credit for
satisfaction of any deductible, co-payment, or similar out-of-pocket payment
requirement under the Replacement Welfare Plans to the extent of the deductible,
co-payments, and similar out-of- pocket payments paid prior to the Closing Date
under the Sellers' Welfare Plans (on a pro-rata basis in the event of a
difference in plan years).
(e) The Buyer shall credit the service of each Transferred Non-Union
Employee with the Sellers and their Affiliates, including, without limitation,
accrued vacation and sick time, for purposes of eligibility, participation,
vesting, and accrual of or entitlement to benefits under all employee benefit
plans, programs, and arrangements of the Buyer and its Affiliates, without
regard to the coverage of any such plan, program, or arrangement by ERISA or any
provision of the Code ("Buyer Benefit Plans") in which they become participants
to the same extent as if such service had been performed for the Buyer or its
designee; provided that the benefits provided under the Buyer Benefit Plans may
be offset by the nonforfeitable benefits previously provided by the Sellers or
the Sellers' Benefit Plans with respect to the same period of service.
(f) Each Transferred Non-Union Employee who is eligible to participate in
the Maine Public Service Company Non-Union Retirement Savings Plan ("Sellers'
Non-Union 401(k) Plan") immediately before the Closing Date shall be eligible
to participate in Wisconsin Public Service Corporation Administrative Employees'
Savings Plan, a tax-qualified defined contribution plan including a cash-or-
deferred arrangement of the Buyer or one of its Affiliates ("Buyer's 401(k)
Plan") as of the Closing Date. The Buyer shall take any and all necessary action
to cause the
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trustee of a tax-qualified defined contribution plan of the Buyer or one of its
Affiliates, if requested to do so by a Transferred Non-Union Employee, to accept
a direct "rollover" of all or a portion of said employee's distribution from the
Sellers' Non-Union 401(k) Plan.
(g) The Buyer shall make (or cause to be made) any and all amendments to
its employee benefit plans, programs, and arrangements necessary to give effect
to its obligations under this Agreement, which amendments shall be effective as
of the Closing Date and delivered to the Sellers within a reasonable time after
the Closing Date.
(h) Provided Buyer has given Sellers at least seventy-five (75) days
advance written notice and Sellers have not extended an offer of comparable
employment, the Buyer shall pay to each Transferred Employee whose employment
is involuntarily terminated by the Buyer or its designee within 12 months after
the Closing Date, (except where such employment is terminated for cause,
unless such cause is beyond the control of the Transferred Employee as in the
case of a layoff for lack of work), the severance benefits that would have been
provided to such individual upon such termination by the Sellers under the
Sellers' Employee Transition Plan to the extent identified as to nature and
amount in the Sellers' Employee Transition Plan, had such individual remained
continuously employed by the Sellers and had been eligible under, and covered
by, such plan on the date of such termination; the Seller will reimburse Buyer
for the cost of such severance benefits. With respect to each Transferred
Employee whose employment is involuntarily terminated by the Buyer or its
designee on or after 12 months following the Closing Date but on or before
December 31, 2001 (except where such employment is terminated for cause, unless
such cause is beyond the control of the Transferred Employee as in the case of
a layoff for lack of work), Buyer or its designees shall pay the severance
benefits that would have been provided to such individual upon such termination
by the Sellers under the Sellers' Employee Transition Plan to the extent
identified as to nature and amount in the Sellers' Employee Transition Plan, had
such individual remained continuously employed by the Sellers and had been
eligible under, and covered by, such plan on the date of such termination.
(i) Subject to the other provisions of this Section 7.10, and except as
specifically provided to the contrary in this Agreement:
(1) The Sellers, and not the Buyer or its designee, shall be
responsible and shall assume any and all liability for (A) all compensation,
benefits, and perquisites of any kind due any Transferred Employee on account
of employment by the Sellers before the Closing Date, or the termination of
employment by the Sellers, including, but not limited to, continuation of health
care coverage pursuant to COBRA and compliance with HIPAA; and (B) all notices,
payments, fines, taxes or assessments due to any governmental authority pursuant
to any applicable foreign, federal, state, provincial or local law, common law,
statute, rule or regulation with respect to the employment, discharge or layoff
of employees employed at the Purchased Assets, including, but not limited to,
the WARN Act, the Employment Standards Act (New Brunswick), and any rules or
regulations that have been issued in connection with any of the foregoing.
(2) The Buyer, and not the Sellers, shall be responsible and shall
assume any and all liability for (A) all compensation, benefits, and perquisites
of any kind due any Transferred Employee on account of employment by the Buyer
or its designee on and after the Closing Date,
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or the termination of employment by the Buyer or its designee, including, but
not limited to, continuation of health care coverage pursuant to COBRA and
compliance with HIPAA; and (B) all notices, payments, fines, taxes or
assessments due to any governmental authority pursuant to any applicable
foreign, federal, state, provincial or local law, common law, statute, rule or
regulation with respect to the employment, discharge or layoff of Transferred
Employees by the Buyer or its designee, including, but not limited to, the
WARN Act, the Employment Standards Act (New Brunswick), and any rules or
regulations that have been issued in connection with any of the foregoing.
(j) The Sellers acknowledge that the benefits identified in the Sellers'
Employee Transition Plan are intended to cover all benefits that the Transferred
Employees are entitled to by law and the IBEW Agreements. In the event that any
Transferred Employee successfully claims in a court of competent jurisdiction
that, under applicable law or the IBEW Agreements, severance benefits are due
to such Transferred Employee in addition to those benefits identified as to
nature and amount in the Sellers' Employee Transition Plan, then the Sellers
shall pay directly or reimburse the Buyer for costs and expenses related to any
additional benefits actually paid to such Transferred Employee (as well as costs
and expenses associated with defending such action brought by such Transferred
Employee) by the Buyer or its Affiliates; provided however, that the Sellers
shall only be required to make any such payment or reimbursement if such
benefits (A) arise out of such Transferred Employee's employment with the
Sellers, and (B) are not due to some act or omission by the Buyer or any of its
Affiliates. The Buyer and the Sellers agree that the terms of Section 9.2
hereof shall apply to this Section 7.10(j) as if set forth herein.
7.11 Risk of Loss.
(a) From the date hereof through the Closing Date, all risk of loss or
damage to the property included in the Purchased Assets shall be borne by the
Sellers.
(b) If, before the Closing Date all or any portion of the Purchased Assets
are taken by eminent domain or expropriation or become the subject of a pending
or (to the knowledge of the Sellers) contemplated taking which has not been
consummated, the Sellers shall notify the Buyer promptly in writing of such
fact. If such taking would create a Material Adverse Effect, the Buyer and the
Sellers shall negotiate in good faith to settle the loss resulting from such
taking (including, without limitation, by making a fair and equitable adjustment
to the Purchase Price) and, upon such settlement, consummate the transaction
contemplated by this Agreement pursuant to the terms of this Agreement. If no
such settlement is reached within sixty (60) days after the Sellers have
notified the Buyer of such taking, then the Buyer or the Sellers may terminate
this Agreement pursuant to Section 10.1(f).
(c) If, before the Closing Date all or any material portion of the
Purchased Assets are damaged or destroyed by fire or other casualty, the Sellers
shall notify the Buyer promptly in writing of such fact. If such damage or
destruction would create a Material Adverse Effect and the Sellers have not
notified Buyer of their intention to cure such damage or destruction within
fifteen (15) days after its occurrence, the Buyer and the Sellers shall
negotiate in good faith to settle the loss resulting from such casualty
(including, without limitation, by making a fair and equitable adjustment to the
Purchase Price) and, upon such settlement, consummate the
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transactions contemplated by this Agreement pursuant to the terms of this Agree-
ment. If (i) no such settlement is reached within sixty (60) days after the
Sellers have notified the Buyer of such casualty, or (ii) Sellers have notified
Buyer of their intention to cure in accordance with the preceding sentence, but
(x) Sellers have not proceeded diligently and in good faith to promptly cure
such damage or destruction, or (y) such cure is not completed to Buyer's reason-
able satisfaction not less than 60 days prior to the Termination Date, then the
Buyer or the Sellers may terminate this Agreement pursuant to Section 10.1(f).
7.12 Real Estate Title; Title Insurance; Surveys.
(a) Buyer is currently in the process of obtaining title insurance
commitments, and Sellers are currently in the process of obtaining surveys, for
the Real Estate. Both parties shall diligently pursue the completion of such
matters and each agrees to cooperate with the other toward the goal of providing
a complete set of surveys and title insurance commitments for the Real Estate
meeting the requirements of this Section 7.12 as soon as is practicable but in
any event within sixty (60) days after the date hereof. The date on which such
materials are completed shall be referred to as the "Initial Title Review Date".
(b) Within sixty (60) days after the Initial Title Review Date, the Buyer
shall notify the Sellers in writing of any defects in title that would make the
Sellers unable to convey good and marketable title to the Real Estate free of
Encumbrances other than Permitted Encumbrances, whether such defects are
disclosed herein or in the surveys and title commitments referred to above (any
of which is called herein a "Defect of Title"). The Buyer shall be deemed to
have waived any objection to any Defect of Title that existed as of the
effective date of the title insurance commitments that are provided on the
Initial Title Review Date if the Buyer fails to notify the Sellers of such
Defect of Title within such sixty-day period. If Sellers notify Buyer that they
are, despite reasonable efforts, unable to cure a Defect of Title (including
obtaining affirmative coverage through Buyer's title insurance company) then
Buyer shall elect, within thirty (30) days after receipt of Seller's notice,
either (i) to accept title to the Real Estate subject to the uncured Defects of
Title, or (ii) if such uncured Defect of Title constitutes a Material Adverse
Effect, to terminate this Agreement in accordance with Section 10.1(e); Buyer's
failure to so elect within such time period shall constitute an election to
accept title subject to such uncured Defect of Title. With respect to any
Defect of Title that does not exist on the effective date of the title insurance
commitments that are provided on the Initial Title Review Date, but which arises
prior to Closing, the Buyer shall notify the Sellers in writing of any such
Defect of Title on or prior to the Closing. The Sellers shall have, at their
option, a period of not more than 90 days after receipt of any such notice
within which to remedy or cure any such Defect of Title to the reasonable
satisfaction of the Buyer. If the Sellers elect to remedy or cure such Defect
of Title, then the Closing shall be extended, if necessary, to a date that is
not more than five (5) business days after the expiration of such 90-day period.
If such Defect of Title is not corrected or remedied to the reasonable
satisfaction of the Buyer within such 90-day period, the Buyer shall elect, by
written notice to the Sellers within ten (10) days after the expiration of such
90-day period, either (i) to accept title to the Real Estate subject to the
uncured Defects of Title, or (ii) if such uncured Defect of Title constitutes
a Material Adverse Effect, to terminate this Agreement in accordance with
Section 10.1(e); Buyer's failure to so elect within such time period shall
constitute an election to accept title subject to such uncured Defect of Title.
Sellers shall have the option to
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provide affirmative title insurance coverage over (which Buyer, at Sellers'
expense, shall assist in attempting to obtain and provided that Sellers are
responsible for any increase in cost attributable to such coverage), or to
indemnify Buyer pursuant to Section 9.1 against, one or more uncured Defects of
Title. Any such indemnification shall be subject to the limitations of Section
9.1(g)(2) and (3), but shall not be subject to the time limitations of Section
9.1 (g)(1). Notwithstanding the prior two sentences, Buyer shall not be
required to accept an indemnity from Sellers with respect to any Defects of
Title.
(c) The title insurance commitments referred to herein shall be issued by
a title insurance company or companies reasonably satisfactory to Buyer,
agreeing to issue to Buyer or its designee standard form owner's policies of
title insurance with respect to all Real Estate, together with a copy of each
document to which reference is made in such commitments. To the extent that
title insurance is not available for the Canadian Real Estate, then Buyer shall
obtain the equivalent thereof commonly used for commercial transactions in New
Brunswick, Canada. Such policies shall be standard ALTA form 1992 owner's
policies (or the Canadian equivalent in respect of the Canadian Real Estate) in
the full amount of the fair value of the Real Estate allocated respectively to
each subject parcel of Real Estate under Section 3.3 hereof, insuring good and
marketable title thereto (expressly including all easements and other
appurtenances). All policies shall insure title in full accordance with the
representations and warranties set forth herein and shall be subject only to
such conditions and exceptions as shall be reasonably acceptable to Buyer and
shall contain such endorsements as Buyer shall reasonably request.
(d) The surveys of the Real Estate shall be prepared in accordance with
ALTA/ACSM 1997 standards, or the Canadian equivalent in respect of the Canadian
Real Estate, each detailing the legal description, the perimeter boundaries, all
improvements located thereon, all easements and encroachments affecting each
such parcel of Real Estate and such other matters as may be reasonably requested
by Buyer or the title insurance companies, each containing a surveyor
certificate reasonably acceptable to Buyer and the title insurance companies,
and each prepared by a registered land surveyor in the jurisdiction where the
Real Estate is located reasonably satisfactory to Buyer.
(e) Sellers and Buyer agree to use the descriptions set forth in the
surveys referred to above, once they have been accepted by Buyer, as the deed
descriptions for the Real Estate.
(f) Sellers and Buyer agree that the aggregate out-of-pocket cost of
obtaining the title insurance commitments and final policy coverage (and the
Canadian equivalent), and the surveys referred to in this Section 7.12 shall be
paid half by the Sellers and half by the Buyer and that Sellers and Buyer intend
to rely upon such surveys for all matters relating to real property descriptions
and the status of title, except as otherwise provided in Section 7.12(b), and
that such surveys shall run to the benefit of Sellers and Buyer. Furthermore,
Buyer agrees that it shall not pursue the Sellers under their deeds to the Real
Estate until it has first obtained whatever it may be owed under its owner's
title insurance policies with respect to such claims.
7.13 Wyman Agreements. MPS agrees that it shall deliver any notices to the
Owners (as defined in the Wyman Agreements) required under the Wyman Agreements
as a result of the proposed transfer to Buyer or its designee of MPS's interest
thereunder.
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ARTICLE VIII
CONDITIONS PRECEDENT
8.1 Conditions to Each Party's Obligations. The respective obligations
of each party to consummate the transactions contemplated hereunder shall be
subject to the fulfillment at or prior to the Closing Date of the following
conditions:
(a) No preliminary or permanent injunction or other order or decree by any
national, federal, provincial or state court which prevents the consummation of
the sale of the Purchased Assets or the assumption of the Assumed Obligations
contemplated hereby shall have been issued and remain in effect (each party
agreeing to use its reasonable best efforts to have any such injunction, order
or decree lifted) and no statute, rule or regulation shall have been enacted by
any national, federal, provincial or state government or governmental agency in
the United States or Canada which prohibits the consummation of the sale of the
Purchased Assets or the assumption of the Assumed Obligations;
(b) All national, federal, provincial, state, and local government
consents and approvals required for the consummation of the sale of the
Purchased Assets and the assumption of the Assumed Obligations contemplated
hereby, the Sellers Required Regulatory Approvals and the Buyer Required
Regulatory Approvals shall have been obtained or become Final Orders (a "Final
Order" for all purposes of this Agreement means a final order after all
opportunities for rehearing are exhausted (whether or not any appeal thereof is
pending) that has not been revised, stayed, enjoined, set aside, annulled or
suspended, with respect to which any required waiting period has expired; and
as to which all conditions to effectiveness prescribed therein or otherwise by
law, regulation or order have been satisfied) and such Final Orders shall not
impose materially adverse terms or conditions; and
(c) All consents and approvals for the consummation of the sale of the
Purchased Assets and the assumption of the Assumed Obligations contemplated
hereby required under the terms of any note, bond, mortgage, indenture, contract
or other agreement (except the Sellers' Agreements) to which the Sellers or any
of their subsidiaries, are a party shall have been obtained, other than those
which if not obtained, would not, in the aggregate, create a Material Adverse
Effect.
8.2 Conditions to Obligations of the Buyer. The obligation of the Buyer
to consummate the transactions contemplated hereunder shall be subject to the
fulfillment at or prior to the Closing Date of the following additional
conditions:
(a) There shall not have occurred and be continuing a Material Adverse
Effect;
(b) The Sellers shall have performed and complied with in all material
respects all covenants and agreements contained in this Agreement and the other
Closing Documents which are required to be performed and complied with by the
Sellers on or prior to the Closing Date, and the representations and warranties
of the Sellers set forth in this Agreement and in the other Closing Documents
shall be true and correct in all material respects as of the date hereof or
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thereof, as the case may be, and as of the Closing Date as though made at and
as of the Closing Date; provided, however, a failure of this condition shall not
constitute a failure for purposes of consummating the Closing unless such fail-
ure materially and adversely affects the Purchased Assets, or Buyer's ability
to finance the acquisition of the Purchased Assets or to operate the Purchased
Assets;
(c) There shall be no Encumbrances on the Purchased Assets, other than
Permitted Encumbrances;
(d) The Buyer shall have received certificates from authorized officers
of the Sellers, dated the Closing Date, to the effect that, to such officers'
knowledge, the conditions set forth in Sections 8.2(a), (b) and (c) have been
satisfied;
(e) MPS shall have assigned to the Buyer or its designee all of its rights
and obligations in the IBEW Agreements as they relate to the Transferred IBEW
Employees, to be employed at or in conjunction with the U.S. Assets after the
Closing Date;
(f) MNB shall have assigned to the Buyer or its designee all of its rights
and obligations in the IBEW Agreements as they relate to the Transferred IBEW
Employees to be employed at or in conjunction with the Canadian Assets after the
Closing Date;
(g) The Buyer shall have received an opinion from Verrill & Dana, LLP, or
other counsel reasonably acceptable to Buyer, dated the Closing Date and
substantially in the form of Exhibit G-1. As to any matter contained in such
opinion which involves the laws of any jurisdiction other than the Federal laws
of the United States or the laws of the State of Maine, such counsel may rely
upon opinions of counsel admitted in such other jurisdictions. Any opinions
relied upon by such counsel as aforesaid shall be delivered together with the
opinion of such counsel. Such opinion may expressly rely as to matters of fact
upon certificates furnished by MPS and appropriate officers and directors of MPS
and by public officials;
(h) The Buyer shall have received an opinion from Clark, Drummie &
Company, dated the Closing Date and substantially in the form of Exhibit G-2.
As to any matter contained in such opinion which involves the laws of any
jurisdiction other than the national laws of Canada or the laws of the Province
of New Brunswick, such counsel may rely upon opinions of counsel admitted in
such other jurisdictions. Any opinions relied upon by such counsel as aforesaid
shall be delivered together with the opinion of such counsel. Such opinion may
expressly rely as to matters of fact upon certificates furnished by the Sellers
and appropriate officers and directors of the Sellers and by public officials;
(i) The Buyer or its designee shall have obtained an interconnection
agreement, in form and substance reasonably satisfactory to the Buyer, with New
Brunswick Power Company, on or before September 30, 1998, for the benefit of the
Tinker Generating Facility and the transmission lines associated therewith, and
such agreement shall be in full force and effect;
(j) The Buyer shall have obtained all Permits and Environmental Permits
necessary for the Buyer or its designee to own, operate and maintain the
Purchased Assets and to deliver the
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output thereof to MPS's transmission system at the respective interconnection
points specified in the Interconnection Agreements, and to perform its covenants
and agreements hereunder and under the other Closing Documents;
(k) All consents and approvals for the consummation of the sale of the
Purchased Assets (including, without limitation, the assignment of the Sellers'
rights, benefits, and interests under the Sellers' Agreements to the Buyer or
its designee) and the assumption of the Assumed Obligations contemplated hereby
required under the terms of any of the Sellers' Agreements shall have been
obtained by the Sellers;
(l) The Buyer shall have received, for delivery to Buyer's lenders, all
consents (including, without limitation, consents to the collateral assignment
in favor of the Buyer's lenders of the Closing Documents and/or of contracts or
agreements included in the Purchased Assets), agreements, certificates,
opinions, and other documents or instruments by or on behalf of the Sellers as
may have been reasonably requested by the Buyer's lenders in connection with the
financing, on a non- or limited recourse basis or otherwise, of Buyer's
acquisition of the Purchased Assets hereunder; and
(m) The Buyer shall have received the certificate or certificates from
each applicable taxing authority required pursuant to Section 7.8(a).
8.3 Conditions to Obligations of the Sellers. The obligation of the
Sellers to consummate the transactions contemplated by this Agreement shall be
subject to the fulfillment at or prior to the Closing Date of the following
additional conditions:
(a) The Buyer shall have performed in all material respects its covenants
and agreements contained in this Agreement and the other Closing Documents which
are required to be performed on or prior to the Closing Date;
(b) The representations and warranties of the Buyer which are set forth
in this Agreement and the other Closing Documents shall be true and correct in
all material respects as of the date hereof or thereof, as the case may be, and
as of the Closing Date as though made at and as of the Closing Date;
(c) The Sellers shall have received a certificate from an authorized
officer of the Buyer, dated the Closing Date, to the effect that, to such
officer's knowledge, the conditions set forth in Sections 8.3(a) and (b) have
been satisfied;
(d) The Buyer or its designee shall have assumed, as set forth in Section
7.10, all of the applicable obligations under the IBEW Agreements as they relate
to Transferred IBEW Employees to be employed at or in conjunction with the
Purchased Assets after the Closing Date;
(e) The Sellers shall have received an opinion from Foley & Lardner,
counsel for the Buyer, dated the Closing Date and substantially in the form of
Exhibit H. As to any matter contained in such opinion which involves the laws
of any jurisdiction other than the federal laws of the United States and
the State of Wisconsin, such counsel may rely upon opinions of counsel
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admitted in such other jurisdictions. Any opinions relied upon by such counsel
as aforesaid shall be delivered together with the opinion of such counsel. Such
opinion may expressly rely as to matters of facts upon certificates furnished
by appropriate officers and directors of the Buyer and its subsidiaries and by
public officials.
ARTICLE IX
INDEMNIFICATION
9.1 Indemnification.
(a) The Sellers will jointly and severally indemnify, defend and hold
harmless the Buyer from and against any and all claims, demands or suits (by any
Person), losses, liabilities, damages (including consequential or special
damages), obligations, payments, costs and expenses (including, without
limitation, the costs and expenses of any and all actions, suits, proceedings,
assessments, judgments, settlements and compromises relating thereto and
reasonable attorneys' fees and reasonable disbursements in connection therewith)
(each, an "Indemnifiable Loss"), asserted against or suffered by the Buyer
relating to, resulting from or arising out of (i) any breach by the Sellers of
any covenant or agreement of the Sellers contained in this Agreement or in any
of the Closing Documents or the inaccuracy or breach as of the date hereof or
thereof, as the case may be, or on the Closing Date of any representation or
warranty of the Sellers in this Agreement or in any of the Closing Documents,
or (ii) the Excluded Liabilities. Notwithstanding the foregoing, the Sellers
shall have no liability hereunder after the Closing Date with respect to the
condition of title of the Real Estate, except as set forth in the deeds to the
Real Estate delivered to the Buyer at the Closing. Furthermore, Buyer agrees
that it shall pursue Sellers under their deeds for the Real Estate only after
it has obtained whatever it may be owed under its owner's title insurance
policies with respect to such claims.
(b) The Buyer will indemnify, defend and hold harmless the Sellers from
and against any and all Indemnifiable Losses asserted against or suffered by the
Sellers relating to, resulting from or arising out of (i) any breach by the
Buyer or its designee of any covenant or agreement of the Buyer or its designee
contained in this Agreement or in any of the Closing Documents or the inaccuracy
or breach as of the date hereof or thereof, as the case may be, or on the
Closing Date of any representation or warranty of the Buyer in this Agreement
or in any of the Closing Documents, (ii) the Assumed Obligations (including
those that are assumed by Buyer's designee), or (iii) any actions of the
Observers.
(c) Any Person entitled to receive indemnification under this Agreement
(an "Indemnitee") having a claim under these indemnification provisions shall
make a good faith effort to recover all losses, damages, costs and expenses from
insurers of such Indemnitee under applicable insurance policies so as to reduce
the amount of any Indemnifiable Loss hereunder. The amount of any Indemnifiable
Loss shall be reduced by any amounts actually and irrevocably recovered by the
Indemnitee with respect to such claim or the underlying facts under insurance
policies, (i) net of any increase that will occur, or is reasonably likely to
occur, in insurance premiums payable by the Indemnitee, whether by retrospective
premium adjustments or any other premium increase under the policy or policies
under which the claim is made or any other policy,
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where the increase results directly from filing the insurance claim and (ii)
less, dollar for dollar, the amount by which the insurance claim when filed or
at any time during the applicable policy period, either singly or in the
aggregate with all other claims made under the applicable policy or policies,
exceeds the policy coverage limit; provided, however, that this subsection shall
apply only if this provision does not constitute an improper waiver of the
insurer's rights of subrogation against the Indemnifying Party. Nothing
contained in this Section 9.1(c) shall be deemed to create an obligation of any
party hereto to maintain any form or level of insurance after the Closing, to
name any other party as an additional insured or to obtain approval for any
waiver of rights of subrogation.
(d) The expiration, termination or extinguishment of any representation,
warranty, covenant or agreement, or the time within which to make a claim
hereunder with respect thereto, shall not affect the parties' obligations under
this Section 9.1 if the Indemnitee provided the Person required to provide
indemnification under this Agreement (the "Indemnifying Party") with proper
notice of the claim or event for which indemnification is sought prior to such
expiration, termination or extinguishment.
(e) The rights and remedies of the Sellers and the Buyer under this
Article IX are exclusive and in lieu of any and all other rights and remedies
which the Sellers and the Buyer may have under this Agreement or otherwise for
monetary relief with respect to (i) any breach or failure to perform any
covenant or agreement or representation or warranty set forth in this
Agreement or (ii) the Assumed Obligations or the Excluded Liabilities, as the
case may be, provided, however, that the foregoing limitation shall not apply
to the parties' respective obligations after the Closing Date under the Buy-Back
Agreement, the Continuing Site Agreement, the Interconnection Agreements or
the Instruments of Assumption.
(f) Buyer and Sellers each agree that notwithstanding any provisions in
this Agreement to the contrary, all parties to this Agreement retain their
remedies at law or in equity with respect to willful, knowing or intentional
breaches of this Agreement, including a failure to consummate the Closing
hereunder when and if required to do so.
(g) Except for any willful, knowing or intentional breach or
misrepresentation, as to which claims may be brought without limitation as to
time or amount:
(1) Any claim or action shall be brought under this Article IX for
breach of a representation or warranty within two (2) years after the
Closing Date. Regardless of the foregoing, however, or any other provision
of this Agreement: (A) there shall be no time limitation hereunder on
claims or actions brought for breach of any representation or warranty made
in or pursuant to Sections 5.1, 5.2, 5.3, 6.1, 6.2 or 6.3; (B) a claim or
action brought for breach of any representation or warranty made in or
pursuant to Section 5.11 hereof must be brought within five (5) years
after the Closing Date; (C) any claim or action brought for breach of any
representation or warranty made in or pursuant to Section 5.19 may be
brought at any time until the underlying tax obligation is barred by the
applicable period of limitation under federal, state and foreign laws
relating thereto (as such period may be extended by waiver) and (D) there
shall be no time limitation
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hereunder for claims against Sellers under the deeds to the Real Estate or
with respect to any indemnity given by the Sellers to cure a Title Defect
pursuant to Section 7.12;
(2) An Indemnitee shall not be entitled to indemnification under
this Article IX for breach of a representation or warranty unless the
aggregate of the Indemnifying Party's indemnification obligations to the
Indemnitee pursuant to this Article IX (but for this Section 9.1(g)(2))
exceeds $100,000; but in such event, the Indemnified Party shall be
entitled to indemnification for amounts in excess thereof; and
(3) An Indemnifying Party's aggregate indemnification
obligations under this Article IX for breach of a representation or
warranty shall not exceed $3,000,000.
9.2 Defense of Claims.
(a) If any Indemnitee receives notice of the assertion of any claim or of
the commencement of any claim, action, or proceeding made or brought by any
Person who is not a party to this Agreement or any Affiliate of a party to this
Agreement (a "Third Party Claim") with respect to which indemnification is to
be sought from an Indemnifying Party, the Indemnitee will give such Indemnifying
Party reasonably prompt written notice thereof, but in any event not later than
sixty (60) days after receipt of notice thereof. Such notice shall specify this
Section of this Agreement, describe the nature of the Third Party Claim in
reasonable detail and will indicate the estimated amount, if practicable, of the
Indemnifiable Loss that has been or may be sustained by the Indemnitee. The
Indemnifying Party will have the right to participate in or, by giving written
notice to the Indemnitee, to elect to assume the defense of any Third Party
Claim at such Indemnifying Party's own expense and by such Indemnifying Party's
own counsel, and the Indemnitee will cooperate in good faith in such defense.
(b) If within thirty (30) days after an Indemnitee provides written notice
to the Indemnifying Party of any Third Party Claim the Indemnitee receives
written notice from the Indemnifying Party that such Indemnifying Party has
elected to assume the defense of such Third Party Claim as provided in the last
sentence of Section 9.2(a), the Indemnifying Party will not be liable for any
legal expenses subsequently incurred by the Indemnitee in connection with the
defense thereof. If the Indemnifying Party fails to defend a Third Party Claim
actively and in good faith within a reasonable period of time after receipt of
written notice from the Indemnitee to such effect, specifying that the
Indemnitee intends to invoke its rights under this Section, the Indemnitee may
assume the defense of such claim, or compromise or settle such claim, for the
account and risk of the Indemnifying Party, and the Indemnifying Party will
be bound by all such actions of the Indemnitee and liable for all reasonable
expenses thereof. Without the prior written consent of the Indemnitee, the
Indemnifying Party will not enter into any settlement of any Third Party Claim
which would lead to liability or create any financial or other obligation on the
part of the Indemnitee for which the Indemnitee is not entitled to
indemnification hereunder. If a firm offer is made to settle a Third Party
Claim without leading to liability or the creation of a financial or other
obligation on the part of the Indemnitee for which the Indemnitee is not
entitled to indemnification hereunder and the Indemnifying Party desires to
accept and agree to such offer, the Indemnifying Party will give written notice
to the Indemnitee to that effect. If the Indemnitee fails to consent to
such firm offer within ten (10) days after its receipt of such notice,
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the Indemnitee may continue to contest or defend such Third Party Claim and, in
such event, the maximum liability of the Indemnifying Party as to such Third
Party Claim will be the amount of such settlement offer, plus reasonable costs
and expenses paid or incurred by the Indemnitee up to the date of
such notice.
(c) Any claim by an Indemnitee on account of an Indemnifiable Loss which
does not result from a Third Party Claim (a "Direct Claim") will be asserted by
giving the Indemnifying Party reasonably prompt written notice thereof, but in
any event not later than sixty (60) days after the Indemnitee becomes aware
of such claim, stating the nature of such claim in reasonable detail, specifying
this Section of this Agreement and indicating the estimated amount, if
practicable, and the Indemnifying Party will have a period of thirty (30) days
within which to respond to such Direct Claim. If the Indemnifying Party does
not respond within such thirty (30) day period, the Indemnifying Party will
be deemed to have accepted such claim. If the Indemnifying Party rejects such
claim, the Indemnitee will be free to seek enforcement of its rights to
indemnification under this Agreement.
(d) If the amount of any Indemnifiable Loss, at any time subsequent to the
making of an indemnity payment in respect thereof, is reduced by recovery,
settlement or otherwise under or pursuant to any insurance coverage, or pursuant
to any claim, recovery, settlement or payment by or against any other entity,
the amount of such reduction, less any costs, expenses or premiums incurred in
connection therewith, will promptly be repaid by the Indemnitee to the
Indemnifying Party. Upon making any indemnity payment, the Indemnifying Party
will, to the extent of such indemnity payment, be subrogated to all rights of
the Indemnitee against any third party in respect of the Indemnifiable Loss to
which the indemnity payment relates; provided, however, that (i) the
Indemnifying Party will then be in compliance with its obligations under this
Agreement in respect of such Indemnifiable Loss and (ii) until the Indemnitee
recovers full payment of its Indemnifiable Loss, any and all claims of the
Indemnifying Party against any such third party on account of said indemnity
payment is hereby made expressly subordinated and subjected in right of payment
to the Indemnitee's rights against such third party. Without limiting
the generality or effect of any other provision hereof, each such Indemnitee and
Indemnifying Party will duly execute upon request all instruments reasonably
necessary to evidence and perfect the above-described subrogation and
subordination rights, and otherwise cooperate in the prosecution of such claims
at the direction of the Indemnifying Party. Nothing in this Section 9.2(d)
shall be construed to require any party hereto to obtain or maintain any
insurance coverage.
(e) A failure to give timely notice as provided in this Section 9.2 will
not affect the rights or obligations of any party hereunder except if, and only
to the extent that, as a result of such failure, the party which was entitled
to receive such notice was actually prejudiced as a result of such failure.
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ARTICLE X
TERMINATION AND ABANDONMENT
10.1 Termination.
(a) This Agreement may be terminated at any time prior to the Closing Date
by mutual written consent of the Sellers and the Buyer.
(b) This Agreement may be terminated by the Sellers or the Buyer if the
Closing contemplated hereby shall have not occurred on or before the first
anniversary of the date of this Agreement (the "Termination Date"); provided
that the right to terminate this Agreement under this Section 10.1(b) shall not
be available to any party whose failure to fulfill any obligation under this
Agreement has been the cause of, or resulted in, the failure of the Closing to
occur on or before such date; and provided, further, that if on the first
anniversary of the date of this Agreement the conditions to the Closing set
forth in Section 8.1(c) shall not have been fulfilled but all other conditions
to the Closing shall be fulfilled or shall be capable of being fulfilled, then
the Termination Date shall be the day which is eighteen months from the date of
this Agreement.
(c) This Agreement may be terminated by either the Sellers or the Buyer
if (i) any governmental or regulatory body, the consent of which is a condition
to the obligations of the Sellers and the Buyer to consummate the Closing, shall
have determined not to grant its or their consent and all appeals of such
determination shall have been taken and have been unsuccessful, (ii) one or more
courts of competent jurisdiction in the United States or Canada or any state or
province shall have issued an order, judgment or decree permanently restraining,
enjoining or otherwise prohibiting the Closing, and such order, judgment or
decree shall have become final and nonappealable or (iii) any statute, rule or
regulation shall have been enacted by any state or province or federal
government or governmental agency in the United States or Canada which prohibits
the consummation of the Closing.
(d) This Agreement may be terminated by the Sellers if there has been a
material violation or breach by the Buyer of any agreement, representation or
warranty contained in this Agreement which has rendered the satisfaction of any
condition to the obligations of the Sellers to effect the Closing impossible and
such violation or breach has not been waived by the Sellers.
(e) This Agreement may be terminated by the Buyer if there has been a
material violation or breach by either Seller of any agreement, representation
or warranty contained in this Agreement or in any of the other Closing Documents
which has rendered the satisfaction of any condition to the obligations of the
Buyer to effect the Closing impossible and such violation or breach has not been
waived by the Buyer in writing.
(f) This Agreement may be terminated by either of the Sellers or the Buyer
in accordance with the provisions of Section 7.11(b) or (c).
10.2 Procedure and Effect of Termination. In the event of termination of
this Agreement and abandonment of the transactions contemplated hereby by either
or both of the
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parties pursuant to Section 10.1, written notice thereof shall forthwith be
given by the terminating party to the other party and this Agreement shall
terminate and the transactions contemplated hereby shall be abandoned, without
further action by any of the parties hereto. If this Agreement is terminated
as provided herein:
(a) Said termination shall be the sole remedy of the parties hereto with
respect to breaches of any agreement, representation or warranty contained in
this Agreement and none of the parties hereto nor any of their respective
trustees, directors, officers or Affiliates, as the case may be, shall have
any liability or further obligation to the other party or any of their
respective trustees, directors, officers or Affiliates, as the case may be,
pursuant to this Agreement, except in each case as stated in this Section 10.2
and in Sections 7.2(b), 7.3 and 7.7; and
(b) All filings, applications and other submissions made pursuant to this
Agreement, to the extent practicable, shall be withdrawn from the agency or
other Person to which they were made.
ARTICLE XI
MISCELLANEOUS PROVISIONS
11.1 Amendment and Modification. Subject to applicable law, this Agreement
may be amended, modified or supplemented only by written agreement of the
Sellers and the Buyer.
11.2 Waiver of Compliance; Consents. Except as otherwise provided in this
Agreement, any failure of any of the parties to comply with any obligation,
covenant, agreement or condition herein may be waived by the party entitled to
the benefits thereof only by a written instrument signed by the party granting
such waiver, but such waiver or failure to insist upon strict compliance with
such obligation, covenant, agreement or condition shall not operate as a waiver
of, or estoppel with respect to, any subsequent or other failure.
11.3 Notices. All notices and other communications hereunder shall be in
writing and shall be deemed given and received if delivered personally or by
facsimile transmission or mailed by overnight courier or by registered or
certified U.S. mail (return receipt requested), postage prepaid, to the parties
at the following addresses (or at such other address for a party as shall be
specified by like notice; provided that notices of a change of address shall be
effective only upon receipt thereof):
(a) If to the Sellers, to:
Maine Public Service Company
209 State Street
P.O. Box 1209
Presque Isle, Maine 04769
Facsimile: (207) 764-6586
Attention: Frederick C. Bustard
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with a copy to:
Verrill & Dana, LLP
One Portland Square
Portland, ME 04112
Facsimile: (207) 744-7499
Attention: Mark K. Googins, Esq.
(b) if to the Buyer, to:
WPS Power Development, Inc.
677 Baeten Road
Green Bay, Wisconsin 54304
Facsimile: (920) 490-5999
Attention: Gerald L. Mroczkowski
with a copy to:
Foley & Lardner
777 East Wisconsin Avenue
Milwaukee, Wisconsin 53202
Facsimile: (414) 297-4900
Attention: Edward J. Hammond, Esq.
11.4 Assignment. This Agreement and all of the provisions hereof shall be
binding upon and inure to the benefit of the parties hereto and their respective
successors and permitted assigns, but neither this Agreement nor any of the
rights, interests or obligations hereunder shall be assigned by any party
hereto, including by operation of law without the prior written consent of the
other party, nor is this Agreement intended to confer upon any other Person
except the parties hereto any rights or remedies hereunder; except, however,
notwithstanding the foregoing, and in addition to (but without limitation of)
Sellers' agreements and covenants set forth in Section 7.6(d) hereof, the
Sellers agree that this Agreement, and each of the other Closing Documents, may
be collaterally assigned at any time without the Sellers' consent in favor of
the Buyer's lenders as security in connection with the financing, on a non- or
limited recourse basis or otherwise, of Buyer's acquisition of the Purchased
Assets hereunder. Notwithstanding the foregoing, no provision of this Agreement
shall create any third party beneficiary rights in any employee or former
employee of the Sellers (including any beneficiary or dependent thereof) in
respect of continued employment or resumed employment, and no provision of this
Agreement shall create any rights in any such Persons in respect of any benefits
that may be provided, directly or indirectly, under any employee benefit plan,
program or arrangement except as expressly provided for thereunder. To the
extent that a Buyer's designee is the party that is involved with any of the
Purchased Assets after the Closing Date, then any obligations of Buyer hereunder
for the period after the Closing Date shall also be an obligation of such
designee.
11.5 Governing Law. This Agreement shall be governed by and construed in
accordance with the laws of the State of Maine (regardless of the laws that
might otherwise
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govern under applicable Maine principles of conflicts of law) as to all matters,
including but not limited to matters of validity, construction, effect,
performance and remedies.
11.6 Counterparts. This Agreement may be executed in two or more
counterparts, each of which shall be deemed an original, but all of which
together shall constitute one and the same instrument.
11.7 Interpretation. The article and section headings contained in this
Agreement are solely for the purpose of reference, are not part of the agreement
of the parties and shall not in any way affect the meaning or interpretation of
this Agreement.
11.8 Schedules and Exhibits. All Exhibits and Schedules referred to herein
are intended to be and hereby are specifically made a part of this Agreement.
11.9 Entire Agreement. This Agreement, the Confidentiality Agreement, the
Buy-Back Agreement, the Continuing Site Agreement, the Interconnection
Agreements, the Instruments of Assumption, the other Closing Documents, and the
Exhibits, Schedules, documents, certificates and instruments referred to herein
or therein, embody the entire agreement and understanding of the parties hereto
in respect of the transactions contemplated by this Agreement. There are no
restrictions, promises, representations, warranties, covenants or undertakings,
other than those expressly set forth or referred to herein or therein.
It is expressly acknowledged and agreed that there are no restrictions,
promises, representations, warranties, covenants or undertakings contained in
any material made available to the Buyer pursuant to the terms of the
Confidentiality Agreement (including the Offering Memorandum, dated September,
1997, and the Bidder's Questions and Updated Document Index letter dated
December 29, 1997, previously made available to the Buyer by the Sellers). This
Agreement supersedes all prior agreements and understandings between the parties
with respect to such transactions other than the Confidentiality Agreement.
[the remainder of this page is intentionally blank]
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IN WITNESS WHEREOF, the Sellers and the Buyer have caused
this agreement to be signed by their respective duly authorized
officers as of the date first above written.
MAINE PUBLIC SERVICE COMPANY
By: /s/ Paul R. Cariani
Name: Paul R. Cariani
Title: President
MAINE AND NEW BRUNSWICK
ELECTRICAL POWER COMPANY,
LIMITED
By: /s/ Paul R. Cariani
Name: Paul R. Cariani
Title: President
WPS POWER DEVELOPMENT, INC.
By: /s/ Gerald L. Mroczkowski
Name: Gerald L. Mroczkowski
Title: Vice President
P:\MKG\D54240\3327\APA9WPS.wpd
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Exhibit 10(x)
Agreement
Between Wheelabrator-Sherman Energy Company
and
Maine Public Service Company
This Agreement dated October 15th, 1997, by and between Maine Public
Service Company, a Maine corporation (MPS), and the Wheelabrator-Sherman
Energy Company, a partnership organized under the laws of Maine (W/S).
WHEREAS, W/S is the owner of a 17.6 MW wood-burning plant and
equipment located in Sherman Station, Maine (the Facilities);
WHEREAS, on June 4, 1984, MPS entered into a Power Purchase
Agreement (the Power Purchase Agreement) with Sherman Power Company,
which Agreement was assigned to the Signal-Sherman Energy Company on
August 8, 1985, which in turn became the Wheelabrator-Sherman Energy
Company in 1988;
WHEREAS, pursuant to the Power Purchase Agreement, MPS is obligated
to purchase the entire output of the Facility through December 31, 2000,
upon the conditions set forth therein. A copy of the Power Purchase
Agreement is attached to this Agreement as Attachment "A".
WHEREAS, Article II of the Power Purchase Agreement gives either
MPS or W/S the right to renew the Agreement for an additional fifteen
years at a price to be agreed upon or, in the failure of such agreement,
as determined by the Maine Public Utilities Commission in accordance
with the provisions of the Power Purchase Agreement;
WHEREAS, MPS, upon examination and analysis, has concluded that
amending the Power Purchase Agreement as set forth below will
substantially reduce both potential stranded costs and rates to its
customers in the near term and will achieve a net present value savings
-2-
for those customers in the long term and is therefore in its best
interests and the best interests of its customers;
WHEREAS, W/S, upon examination and analysis, has concluded that
amending the Power Purchase Agreement as set forth below will allow it
to continue to operate the Facilities after December 31, 2000, selling
the output thereof to MPS at a price that allows it to meet the capital
and operating expenses of the Facilities; and
WHEREAS, MPS and W/S are willing to amend the Power Purchase
Agreement in the manner set forth herein and as authorized by 35-A
M.R.S.A. s. 3204(4);
NOW THEREFORE, in consideration of the premises and the mutual
representations, warranties and covenants contained herein, MPS and W/S,
each intending to be legally bound, hereby agree as follows:
I. Closing Date
The Closing Date shall be a date determined by agreement of both
parties, but shall not be any later than ten (10) days after the last
to occur of:
(i) MPS obtains final orders or decrees of the Maine Public
Utilities Commission (MPUC) that (a) issue a certificate of
approval for this Agreement under 35-A M.R.S.A. s. 3156, (b) amend
the MPUC's November 30, 1995 Order in Docket No. 95-052 to permit
MPS to reflect any cost reductions set forth in Subsection II in
its 1998 or 1999 price cap adjustments; (c) determine that the
difference between (1) payments to W/S made, or agreed to be made,
by MPS in accordance with the terms of the Agreement and (2) the
market value of the power for which these payments are made, or are
-3-
agreed to be made, is recoverable as stranded costs under, and in
accordance with the terms of, 35-A M.R.S.A. s. 3208; and (d) to the
reasonable satisfaction of W/S, do not disturb, affect or modify
the rights of W/S as a Qualifying Facility under PURPA and under
the Purchase Power Agreement, as set forth by the MPUC in its Order
and Decision dated January 19, 1995 in Docket No. 94-301, except to
the limited extent explicitly agreed to in this Agreement.
(ii) MPS obtains, on terms reasonably satisfactory to it, the
financing necessary to pay W/S the amount set forth in Subsection
II A below, which financing shall have been approved by the MPUC
and the Finance Authority of Maine under the Electric Rate
Stabilization Program upon terms and conditions reasonably
satisfactory to MPS.
(iii) W/S obtains any required consent of its lenders,
bondholders and/or lessors to this Agreement and its performance of
this Agreement.
C. In the event that all of the events described in this section
above and the Closing have not occurred on or before February 1, 1998,
then this Agreement shall become null and void, unless extended by
mutual agreement of the parties.
II. Amendments to June 4, 1984 Power Purchase Agreement.
A. On the Closing Date MPS, in consideration for the amendments
to the Power Purchase Agreement set forth in Subsection B below, shall
pay to W/S the amount of Eight Million Six Hundred Thousand Dollars
($8,600,000) in immediately available funds, provided however, that for
each day the Closing Date is delayed beyond November 1, 1997, there
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shall be added to this amount a daily penalty of two thousand three
hundred fifty dollars ($2,350.00) up to a maximum penalty of one hundred
five thousand seven hundred and fifty dollars ($105,750).
B. MPS and W/S further agree to amend the Power Purchase
Agreement, on the Closing Date, as follows:
1. Under Article I: Definitions, the definition of "Annual
Expected Energy Production" and "Facilities" are deleted and the
following are substituted in their place:
"Annual Expected Energy Productions" (AEEP) is the
expected annual energy production to be sold by Seller to
Buyer and is 126,582 MWH through 2000 and 136,582 MWH
thereafter".
"Facilities" are all of the Seller's plant and equipment
located in Sherman Station, Maine, used to provide energy to Buyer
having a net generating capacity of 17.6 MW."
2. Under Article II: Term, the first paragraph is deleted and the
following is substituted in its place:
"This Agreement will commence on the date hereof, and
will terminate on December 31, 2006".
3. Under Article II: Term, the second paragraph is deleted.
4. Under Article III: Sale of Power, in the second line of the
last paragraph, strike "2000" and substitute therefore "2006".
5. Under Appendix B: Annual Contract Rate, delete the first six
lines, through and including "Option 2:", and add the following:
Year Contract Rate
2001 8.054
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2002 8.215
2003 8.379
2004 8.547
2005 8.718
2006 8.892
The parties further agree that, in order to reduce its monthly
payments to W/S under the Power Purchase Agreement against invoices
issued by W/S to MPS for energy deliveries through December, 2000, MPS
shall receive a monthly credit as follows:
(i) If the Closing Date occurs on or before December 15, 1997, MPS
shall receive a monthly credit of $500,000 against the invoice for
energy deliveries for each of November and December, 1997 and a credit
of $250,000 against each monthly invoice for energy deliveries beginning
with the invoice for energy delivered in January, 1998 and ending with
the invoice for energy delivered in December, 2000.
(ii) If the Closing Date occurs after December 15, 1997, MPS shall
receive against each month's invoice a monthly credit in the amount set
forth in the appropriate column of Appendix B-1, attached hereto. The
appropriate column of Appendix B-1 shall be that column that lists as
the effective date the first day of the month of the first full calendar
month after the Closing Date.
If for any month for which a credit is due MPS under this section
the amount of the invoice to MPS, prior to deducting the credit, is less
than the amount of the credit, then W/S shall forgive payment of that
month's gross invoice and shall also pay to MPS an amount equal to the
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difference between the gross invoice amount and the amount of the
credit, such payment to be made to MPS within 20 working days.
6. Under Appendix C: Ordered Rates: (a) add the following:
Annual Capacity Annual Energy Total Amount
Year Rate cents/KWH Rate cents/KWH Rate cents/KWH
2001 5.438 2.616 8.054
2002 5.547 2.668 8.215
2003 5.657 2.722 8.379
2004 5.771 2.776 8.547
2005 5.886 2.832 8.718
2006 6.004 2.888 8.892
(b) Delete: "Based on a levelized Contract Rate of
9.751 cents/kwh as shown on the final page of Appendix E."
7. At the end of Article IV, Penalties; (a) add the following:
"Notwithstanding any of the foregoing, Seller shall not
be obligated to operate its Facilities after January 1, 2001
if, in Seller's sole discretion, it concludes that continued
operation of the Facilities at the annual Contract Rates set
forth in this Agreement will result in the Facilities
experiencing a financial net operating loss because of either
(i) the cost of fuel at the Facilities, or (ii) changes in
current Federal, State or local laws, rate or regulation
affecting the cost of operating the Facilities. Seller may,
without liability of any kind (including any liability for
rate reductions under this Article 4 (a) and (b)) to Buyer,
its officers, directors, employees and agents, suspend for any
period(s) (including up to December 31, 2006) its performance
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under this Agreement for so long as it determines the
conditions specified in the preceding sentence shall exist.
In order to exercise its right to suspend performance under
this paragraph, Seller shall provide Buyer with 30 days
advance notice and specify the duration of the suspension.
Seller's right to suspend performance under the terms of this
paragraph refers solely to the total cessation of operation of
the Facilities during the period(s) of suspension and not to
any reduction in the Facilities' output. No suspension of
performance under this paragraph shall serve to extend the
term of this Agreement as set forth in Article II."
(b) Delete the phrase in the sixth paragraph: "Regardless of
whether the Seller elects Option 1 or Option 2 in Appendix B
...."
8. Article VI, Notices. Add the following:
"To Seller: General Counsel
Wheelabrator Environmental Systems, Inc.
4 Liberty Lane West
Hampton, NH 03842
Plant Manager
Wheelabrator-Sherman Energy Company
P.O. Box 157
Sherman Station, ME 04777-0157
9. In Article XI, Deliveries, delete the phrase "up to a maximum
of 126,582 MWH" and substitute therefore "up to a maximum of the AEEP".
10. In Article XXV, Arbitration, delete, in the second and third
sentences, the phrase "except those to be submitted to the Maine Public
Utilities Commission under Article II."
-8-
Except as expressly amended above, the June 4, 1984 Power Purchase
Agreement shall remain in full force and effect.
III. The Parties' Warranties and Representations.
Each of the parties to this Agreement hereby represents and
warrants to the other on the date hereof and as of the closing date that
(i) it has full corporate power and authority to enter into this
Agreement and to perform its obligations hereunder and (ii) that its
execution, delivery and performance of this Agreement will not violate,
conflict with, or result in a default under, any material contract,
agreement, rate, mortgage or indenture, or any judgment, order or
decree, to which it is a party or by which its assets are bound.
IV. Miscellaneous.
A. Each party shall be solely responsible for its all out-of-
pocket costs incurred by it or on its behalf in connection with the
preparation, execution and delivery of this Agreement.
B. This Agreement represents the entire agreement and
understanding of the parties hereto with respect to the subject matter
contained herein, and supersedes all prior agreements and understandings
of the parties with respect to said subject matter.
IN WITNESS WHEREOF, the parties have caused this instrument to be
signed and sealed, all as of the day and year first written above.
MAINE PUBLIC SERVICE COMPANY
Witness /s/ Alice E. Shepard By /s/ Paul R. Cariani
Its President
WHEELABRATOR-SHERMAN ENERGY COMPANY
Witness /s/ Robert J. Gagalis By /s/ L.W. Plitch
Its Vice President
Wheelabrator Sherman Station One Inc.
Managing General Partner
Agreement.saj
APPENDIX B-1
MONTHLY CREDIT
Effective Date January 1, 1998 February 1, 1998
Jan. '98 - Dec. '00 (281,166)
Feb. '98 - Dec. '00 (281,166) (288,061)
AMENDMENT TO AGREEMENT
BETWEEN WHEELABRATOR-SHERMAN ENERGY COMPANY
AND
MAINE PUBLIC SERVICE COMPANY
Wheelabrator-Sherman Energy Company and Maine Public Service Company,
for good and valuable consideration, the sufficiency of which is acknowledged
by the parties, hereby amend the "Agreement Between Wheelabrator-Sherman
Energy Company and Maine Public Service" dated October 15, 1997, as amended by
amendment dated January 30, 1998 (hereinafter the "Agreement") as follows:
1. Under Article I "Closing Date", page 3, line 18, the date of May 1, 1998
shall be deleted and the date of June 1, 1998 shall be substituted in its
place, so that the amended sentence now reads: "In the event that all of the
events described in this section above and the Closing have not occurred on or
before June 1, 1998, then this Agreement shall become null and void, unless
extended by mutual agreement of the parties."
2. Appendix B-1 is amended to add the following monthly invoice credits which
shall be applied to each invoice issued after the Closing Date, applicable if
the Closing occurs after February 1, 1998 and on or before June 1, 1998:
Effective Date- March 1, 1998 April 1, 1998 May 1,1998 June 1, 1998
Mar. 98 - Dec. 98 $310,585
Apr. 98 - Dec. 98 $338,101
May 98 - Dec. 98 $372,500
June 98 - Dec. 98 $416,730
Thereafter the credit shall be $288,061 for each monthly invoice through
December, 2000.
3. Except as expressly amended above, the Agreement and the June 4, 1984 Power
Purchase Agreement (as amended by the Agreement) shall remain in full force and
effect.
IN WITNESS WHEREOF, the parties have caused this instrument to be signed
and sealed, all as of the 28th day of April 1998.
MAINE PUBLIC SERVICE COMPANY
Witness /s/ Alice E. Shepard By /s/ Paul R. Cariani
Its President
WHEELABRATOR-SHERMAN ENERGY COMPANY
Witness /s/ Richard T. Felago By Wheelabrator-Sherman Station One, Inc.
Its Managing General Partner
By /s/ L. W. Plitch
Its Vice President
AMENDMENT TO AGREEMENT
BETWEEN WHEELABRATOR-SHERMAN ENERGY COMPANY
AND
MAINE PUBLIC SERVICE COMPANY
Wheelabrator-Sherman Energy Company and Maine Public Service Company,
for good and valuable consideration, the sufficiency of which is acknowledged
by the parties, hereby amend the "Agreement Between Wheelabrator-Sherman
Energy Company and Maine Public Service" dated October 15, 1997, (hereinafter
the "Agreement") as follows:
1. Under Article I "Closing Date", page 3, line 18, the date of February 1,
1998 shall be deleted and the date of May 1, 1998 shall be substituted in its
place, so that the amended sentence now reads: "In the event that all of the
events described in this section above and the Closing have not occurred on or
before May 1, 1998, then this Agreement shall become null and void, unless
extended by mutual agreement of the parties."
2. Appendix B-1 is amended to add the following monthly invoice credits
which shall be applied to each invoice issued after the Closing Date, applica-
ble if the Closing occurs after February 1, 1998 and on or before May 1, 1998:
Effective Date- March 1, 1998 April 1, 1998 May 1,1998
Mar. 98 - Dec. 98 $310,585
Apr. 98 - Dec. 98 $338,101
May 98 - Dec. 98 $372,500
Thereafter the credit shall be $288,061 for each monthly invoice through
December, 2000.
3. Except as expressly amended above, the Agreement and the June 4, 1984 Power
Purchase Agreement (as amended by the Agreement) shall remain in full force and
effect.
IN WITNESS WHEREOF, the parties have caused this instrument to be signed
and sealed, all as of the 30th day of January 1998.
MAINE PUBLIC SERVICE COMPANY
Witness /s/ Alice E. Shepard By /s/ Paul R. Cariani
Its President
WHEELABRATOR-SHERMAN ENERGY COMPANY
Witness /s/ Robert J. Gagalis By Wheelabrator-Sherman Station One, Inc.
Its Managing General Partner
By /s/ L. W. Plitch
Its Vice President
Exhibit 10(y)
PURCHASE AND SALE AGREEMENT
This Purchase And Sale Agreement (the Agreement) by and Between the Loring
Development Authority of Maine, an instrumentality of the State of Maine (the
Seller) and Maine Public Service Company, a corporation organized under the laws
of the State of Maine (the Buyer), is made as of this Ninth day of July, 1998.
Witnesseth
Whereas, the Seller wishes to sell, and the Buyer wishes to purchase, the
assets described in this Agreement;
Now, therefore, in consideration of the mutual covenants, representations,
warranties and agreements herein set forth, and intending to be legally bound
hereby, the parties hereto agree as follows:
Article I. Definitions
As used herein, the following terms have the following meaning:
(1) "CERCLA" means the Federal Comprehensive Environmental Response,
Compensation and Liability Act, as amended.
(2) "Closing Documents" means, collectively, this Agreement, the Leases,
Bills of Sale, Deeds and each of the documents, instruments, certificates,
opinions and agreements that are required to be delivered pursuant to this
Agreement.
(3) "Encumbrances" means any mortgages, pledges, liens, security
interests, conditional and installment sale agreements, activity and use
limitations, conservation easements, deed restrictions, encumbrances and charges
of any kind.
(4) "Environmental Laws" means all Federal, state and local laws, rules,
regulations, ordinances, codes, decrees, judgments, directives, or judicial or
administrative orders relating to pollution or protection of the environment,
natural resources or human health and safety, including, without limitation,
laws relating to release or threatened releases of Hazardous Substances
(including, without limitation, into or through ambient air, surface water,
groundwater, land, surfaces and subsurface strata) or otherwise relating to the
manufacturer, processing, distribution, use, treatment, storage, release,
transport or holding of Hazardous Solutions, including without limitation the
Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act,
the Toxic Substances Control Act and CERCLA, as amended, and their state and
local counterparts.
-2-
(5) "Hazardous Substances" means (a) any petrochemical or petroleum
products, oil or coal ash, radioactive materials, radon gas, asbestos in any
form that is or could become friable, urea formaldehyde foam insulation and
transformers as well as other equipment that contain dielectric fluid that may
contain levels of polychlorinated biphenyls; (b) any chemicals, materials or
substances defined as or included in the definition of "hazardous substance",
"hazardous wastes", "hazardous materials", "restricted hazardous materials",
"toxic substances", "contaminants" or "pollutants" or words of similar
meaning and regulating effect; or (c) any other chemical, material or substance,
exposure to which is prohibited, limited or regulated by any applicable
Environmental Law.
Article II. Purchase And Sale
2.1 The Sale
Upon the terms and subject to the satisfaction of the conditions contained
in the Agreement, at the Closing, the Seller shall sell, assign, convey,
transfer and deliver to the Buyer, and the Buyer will purchase and acquire from
the Seller, free and clear from all Encumbrances, all of the Sellers' right,
title and interest in, to and under the following property:
(a) Except as provided in 2.3 below, the entire electric distribution
system located at the former Loring Air Force Base (LAFB) located in
Limestone, Caribou and Caswell, Maine, as described on Exhibit A to this
Agreement. (The Distribution System) The Distribution System shall
include, without limitation, all poles, conductors, conductor
hardware, transformers, insulators, fuses, switchgear, relays, breakers and
battery boxes, used for the delivery of electric energy and capacity at
distribution voltages (34.5 kw and lower) at the former LAFB.
(b) All tools, equipment, inventory and personal property associated with
the Distribution System substantially as set forth in Exhibit B to this
Agreement.
(c) Such intangible property, including and without limitation, easements,
rights of way and other licenses as shall be deemed by Buyer necessary or
desirable for the operation and maintenance of the Distribution System and
as are set forth in Exhibit C to this Agreement.
The property described in Section 2.1 (b) and (c) above shall also be
deemed to be included in any further references to the "Distribution
System" in this Agreement.
2.2 Excluded Liabilities And Obligations.
The Buyer shall not assume or be obligated to pay, perform or otherwise
discharge any liabilities or obligations of the Seller (fixed or contingent,
known or unknown), whether or
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not relating to the Distribution System. Without limitation of the forgoing,
the Buyer shall not assume any of the following:
(a) Any liability, obligation or responsibility under or
related to former, current or future Environmental Laws or
the common law arising as a result of or in connection with
(i) any violation or alleged violation of any Environmental
Law, on or before the Closing Date, with respect to the
ownership, use or operation of the Distribution System; (ii)
compliance with applicable Environmental Laws on or before
the Closing Date with respect to the ownership, use or
operation of the Distribution System; (iii) loss of life,
injury to persons or property or damage to natural resources
caused, or alleged to be caused, by the presence or release
of Hazardous Substances at, on, in under, adjacent to or
migrating from the Distribution System on or before the
Closing Date, including but not limited to, Hazardous
Substances contained in the soil, groundwater or other
environmental media at or adjacent to the Distribution
System; (iv) loss of life, injury to persons or property or
damage to natural resources caused, or alleged to be caused,
by the off-site disposal, storage, transportation, release,
recycling, or the arrangement for such activities, of
Hazardous Substances, on or before the Closing Date, in
connection with the ownership, use or operation of the
Distribution System; (v) the investigation and/or
remediation of Hazardous Substances that are present or
have been released on or before the Closing Date at, on, in,
under, adjacent to or migrating from the Distribution
System, including but not limited to, Hazardous Substances
contained in the soil, groundwater or in other environmental
media at or adjacent to the Distribution System; and (vi)
the investigation and/or remediation of Hazardous
Substances that are disposed, stored, transported, released,
recycled, or the arrangement of such activities, on or
before the Closing Date, in connection with the ownership or
operation of the Distribution System, at any off-site
location;
(b) Any liabilities or obligations relating to or arising
out of any claim, action, suit or proceeding arising as of
the Closing Date, or any subsequent claim, action, suit or
proceeding arising out of or relating to such pending
matters, any other event occurring on or prior to the Closing Date, or
resulting from the ownership, use or operation of the Distribution System
on or prior to the Closing Date, or resulting from loss of life, injury to
persons or property arising from or related to the ownership, use or
operation of the Distribution System on or prior to the Closing Date;
(c) Any payment obligations of the Seller for goods delivered or services
rendered on or prior to the Closing Date.
-4-
2.3 Excluded Property.
The property to be transferred to Buyer pursuant to this Agreement shall
not include any of the switchgear, or any associated equipment or facilities,
located in Building 7240 at the former LAFB (the Excluded Property). Buyer
shall not, by this Agreement or any conveyance from Seller, acquire any right,
title or interest to or in the Excluded Property. Notwithstanding the
foregoing, Seller shall grant to Buyer, pursuant to 2.1(c) above, all easements,
licenses or rights of way deemed by Buyer necessary or desirable for the
operation and maintenance of the Excluded Property, including the right to
physically segregate, by partition or otherwise, the Excluded Property. As
consideration for the foregoing, Buyer agrees to assume sole responsibility for
the operation, maintenance, repair, upgrading or replacement, as it deems
proper, of any or all of the Excluded Property, provided that this obligation
shall not subject Buyer to, or require it to assume any of, the liabilities,
obligations or responsibilities set forth in Subsection 2.2(a) above, for the
purpose of which Subsection only the Excluded Property shall be deemed to be
part of the Distribution System. Seller shall, in addition, reimburse Buyer
for any expense it shall incur during the operation, maintenance, repair,
upgrade or replacement of the Excluded Property as a result of or on account of
the presence or release of any Hazardous Substances.
Article III. Purchase Price
3.1 Purchase Price.
The Purchase price for the Distribution System shall be $250,000.
3.2 Proration.
The parties agree that all of the items normally prorated, including
without limitation, personal property and real estate taxes, and any permit and
license fees, relating to the business, use and operation of the Distribution
System shall be prorated as of the Closing Date, with the Seller liable to the
extent such items relate to any period prior to the Closing Date, and the Buyer
liable to the extent such items relate to any period after the Closing Date.
Article IV. The Closing
4.1 Time And Place.
Upon the terms and subject to the satisfaction of all conditions contained
in this Agreement, the closing of the sale of the Distribution System
contemplated by this Agreement will take place at the Seller's offices at such
time and on such day as the parties may agree, but no later than ten business
days following the date on which all such conditions have been
satisfied or waived (the Closing Date).
-5-
4.2 Payment of Purchase Price.
Upon the terms and subject to the satisfaction of the conditions contained
in this Agreement, in consideration of the aforesaid sale, assignment,
conveyance, transfer and delivery of the Distribution System, the Buyer will pay
to Seller, as Seller may direct, at the Closing an amount of $250,000 in
immediately available funds.
4.3 Deliveries By Seller.
At the Closing, the Seller will delivery the following to the Buyer:
(a) Except as provided in (b) below, with respect to so much of the
Distribution System to which Seller shall not have acquired title on or
prior to the Closing Date, an exclusive and irrevocable leasehold interest,
duly executed by Seller, to the Distribution System conveying to the Buyer
full use and occupation (which shall not, in any event, convey less than
all rights or interests that the Seller may possess on the Closing Date
with respect to the Distribution System) of the Distribution System
together with all easements and rights of way that Buyer deems necessary
or desirable with respect to the exercise of this leasehold. The form of
this leasehold and associated easements and rights of way shall be agreed
to by the parties prior to the Closing Date.
(b) For so much of the Distribution System to which Seller has acquired
title on or prior to the Closing Date; (i) A bill of sale, duly executed
by Seller, for all personal property included in the Distribution System
(ii) A quitclaim deed with covenants, duly executed by Seller, for
any real estate included in the Distribution System (iii) The easements,
rights of way and other licenses, duly executed by Seller, as are required
for the operation and maintenance of the Distribution System as set forth
in Exhibit C of this Agreement.
(c) The Agreement required by Section 5.1 below.
(d) Copies of all books, records and other documents in the Seller's
possession and related to the Distribution System, as shall be requested
by Buyer.
(e) Opinions of counsel and certificates as contemplated by Section 8.2.
(f) All other instruments of assignment or conveyance as shall, in the
Buyers's reasonable opinion, be necessary to transfer to the Buyer the
Distribution System, in recordable form.
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4.4 Deliveries By Buyer.
At the Closing, the Buyer will deliver the following to the Seller:
(a) The Purchase Price, referred to in Section 4.2;
(b) Opinions of counsel and certificates as contemplated by Section 8.3;
(c) The Agreements required by Section 5.2 below.
Article V. Surviving Obligations of the Parties
The performance of the following obligations are essential to the purchase
and sale contemplated by the Agreement and shall survive the Closing set forth
in Article IV above.
5.1 Obligations of the Seller.
The parties recognize that, after the Closing Date, the Federal Government
will transfer to the Seller title to that portion of the Distribution System to
which Seller does not have title as of the Closing Date. The Seller hereby
agrees that it shall, within ten business days of obtaining such title, deliver
to the Buyer, with respect to the property described in this Section 5.1, and
without any additional consideration, those instruments described in Section
4.3(b) above as are necessary to convey full title to Buyer. The Seller shall
deliver to the Buyer, at the Closing and in a form acceptable to the Buyer, an
agreement reflecting the obligations set forth in this section.
5.2 Obligations of the Buyer.
(a) Within such reasonable time after the Closing as the parties shall
agree to, Buyer shall demolish and remove as much of the Distribution System
located at the North and South Wherry housing facilities at the former LAFB that
it is directed by the Seller to demolish and remove. Buyer shall not charge
Seller for this service; provided, however, the Buyer shall charge Seller, and
Seller shall pay Buyer, at Buyer's standard customer rate for said service, for
the demolition and removal of all property of any other utility company located
at said facilities. The Buyer shall deliver to the Seller, at the Closing and
in a form acceptable to Seller, an agreement reflecting the obligation set forth
in this section.
(b) Within ten business days after the Closing, Buyer shall file with the
Maine Public Utilities Commission (MPUC) for approval of an economic development
rider to Buyer's special facility changes under which any customer taking
electric service from the Distribution System at the former LAFB could
receive a discount of up to 50% off the costs of installing underground
distribution facilities. This rider shall not be effective for more than two
years after its approval by the MPUC. The Buyer will use all reasonable efforts
to obtain approval of this rider.
-7-
(c) Buyer shall perform, in accordance with its terms, a certain letter
agreement, dated June 22, 1998, by and between itself and Bell Atlantic,
pursuant to which Buyer shall transfer a half-interest in certain utility poles
to Bell Atlantic. Nothing herein is intended or shall be deemed to confer upon
Seller any third party beneficiary status or any other interest in, to or under
said letter agreement.
Article VI. Representation And Warranties
A. Mutual
6.1 Authority Relative To This Agreement.
Each of the parties hereby warrants and represents that they have full
corporate power and authority to execute and deliver this Agreement and each of
the other Closing Documents to which they are a party and to consummate the
transactions contemplated hereby and thereby.
Each of the parties hereby warrants and represents that neither the
execution and delivery of this Agreement and the other Closing Documents to
which they are party nor the consummation of the transactions contemplated
hereby and thereby will (i) conflict with or result in any breach of any
provision of their respective organizational documents or bylaws; (ii)
require any consent, approval, authorization or notification of any governmental
or regulatory authority; (iii) result in or constitute a default, or give rise
to any right of termination, cancellation, acceleration, or result in the
creation of any Encumbrance upon any of the assets of the Sellers, under any of
the terms, conditions or provisions of any note, bond, mortgage, indenture,
license or any other instrument or obligation to which either party is a party
or by which either may be bound; or (iv) violate any order, writ, injunction,
decree, statute, rule or regulation applicable to either of the parties, or any
of their respective assets.
B. Seller's
6.2 Title to and Condition of Distribution System
The Seller warrants and represents that it has either (i) good and
marketable title to the Distribution System, free and clear of all Encumbrances
or, (ii), with respect to any property to which it does not have good and
marketable title as of the Closing, a leasehold interest in the Distribution
System on which the only Encumbrance is the prior title of the Federal
government and that the Distribution system is not subject to any restrictions
with respect to the transferability thereto. Buyer, either at Closing or
pursuant to the transfer contemplated in Section 5.1, will receive good and
marketable title to all the Distribution system, free and clear of all
Encumbrances of any nature whatsoever.
-8-
Exhibit D hereto lists, as of the date of this Agreement, all leases under
which the Seller is a lessee or lessor and that relate to the Distribution
System or the operation of the Distribution System. All such leases are valid,
binding and enforceable is in accordance with their terms, and are in full
force and effect; there are no existing material defaults by the Seller or any
other party thereunder; and no event has occurred that would constitute a
material breach by the Seller or any other party.
6.3 Environmental Matters
The Seller holds and is in full compliance with all of the permits,
licenses, and governmental authorizations required for the Sellers to operate,
maintain and engage in business related to the Distribution System under all
applicable Environmental Laws, and the Seller is otherwise in compliance with
all applicable Environmental Laws with respect to the Distribution System or the
operation and maintenance of the Distribution System.
The Seller has not received any written request for information or been
notified that it is a potentially responsible party under CERCLA or any other
Environmental Law.
The Seller has not entered into or agreed to any consent decree or order,
and is not subject to any outstanding judgment, decree or order relating to
compliance with any Environmental Law or to investigation or clean-up of
Hazardous Substances under any Environmental Law.
6.4 Taxes
With respect to the Distribution System, and any businesses or trades
associated with it, (i) all tax returns required to be filed have been filed and
(ii) all taxes shown to be due on such tax returns have been paid in full. No
notice of deficiency or assessment has been received from any taxing authority
with respect to liability for taxes of the Seller in respect of the Distribution
System.
Article VII
Covenants of the Parties
7.1 Conduct of Business
During the period from the date of this Agreement to the Closing Date, the
Seller will operate, or cause to be operated, the Distribution System in the
usual, regular and ordinary course consistent with good industry practices and
shall use all reasonable efforts to preserve intact the Distribution System.
Without limiting the generality of the foregoing, prior to the Closing Date,
without Buyer's prior written consent, the Seller shall not with respect to the
Distribution system, and except in the ordinary course of business:
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(a) create, incur, assume or suffer to exist any indebtedness;
(b) make any material change in the levels of inventory maintained by the
Seller with respect to the Distribution System;
(c) sell, lease, transfer or otherwise dispose of, any of the Distribution
System, other than assets used, consumed or replaced in the ordinary course of
business; and
7.2 Access to Information
For a period of six years after the Closing Date, each party and its
representatives shall have reasonable access to all books and records relating
to the Distribution System in the possession of the other party to the extent
that such access may reasonably be required by such party in connection with any
matters relating to or affected by the operation of the Distribution System.
Such access shall be afforded upon receipt of reasonable advance notice and
during normal business hours. The party exercising this right of access shall
be solely responsible for any costs or expenses incurred by it. If the
party in possession of such books of accounts shall desire to dispose of them
prior to the expiration of the six years, it shall, prior to such disposition,
give the other party reasonable opportunity to segregate and remove such books
and accounts, at its own expense.
7.3 Further Assurance
Subject to the terms and conditions of this Agreement, each of the parties
hereto will use all reasonable efforts to take, or cause to be taken, all
action, and to do, or cause to be done, all things necessary and proper to
consummate and make effective the sale of the Distribution System pursuant to
this Agreement. Neither of the parties will take or fail to take any
action that would reasonably be expected to prevent or materially impede,
interfere with or delay the transactions contemplated by this Agreement.
7.4 Fees
The parties represent and warrant to each other than no broker, finder or
other person is entitled to any brokerage fees, commissions and finder's fees
in connection with the transaction contemplated hereby by reason of any action
taken by the party making such representation.
7.5 Tax Matters
(i) All transfer and sales taxes incurred in connection with this
Agreement and the transactions contemplated hereby shall be borne by the Seller,
other than Maine real estate transfer taxes, which shall be borne equally by
Buyer and Seller, and Buyer, at its own expense, will file all required
tax returns and other transactions with respect to all such taxes.
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(ii) Each party shall provide the other with such assistance as may
reasonably be requested by the other in connection with the preparation of any
tax return, any audit or other examination by any taxing authority, or any
proceeding relating to liability for taxes.
7.6 Risk of Loss
(a) From the date hereof, through the Closing Date, all risk of loss or
damage to the Distribution System shall be borne by the Seller.
(b) If, before the Closing Date, all or any portion of the Distribution
System is damaged or destroyed by fire or other casualty, the Seller shall
notify the Buyer promptly in writing of such fact. If Buyer determines that
this damage or destruction has a material adverse effect on the Distribution
System, the Buyer and the Seller shall negotiate in good faith to settle the
loss resulting from such casualty (including, without limitation, by adjusting
the Purchase Price) and, upon such settlement, consummate the transactions
contemplated by this Agreement pursuant to its terms. If no such settlement is
reached within sixty days after notice of the casualty, then either party may
terminate this Agreement.
7.7 Surviving Obligations
Each party shall perform its respective obligations as set forth in Section
5.1 and 5.2 of this Agreement.
Article VIII
Conditions Precedent
8.1 Mutual
The respective obligations of each party to consummate the transactions
contemplated hereunder shall be subject to the fulfillment at or prior to the
Closing Date of the following conditions:
(i) All consents and approvals for the consummation of the sale
contemplated hereunder required by any note, bond, mortgage, indenture, contract
or other agreement to which either the Seller or the Buyer is a party shall have
been obtained.
8.2 Buyer's
The obligation of the Buyer to consummate the transactions contemplated
hereunder shall be subject to the fulfillment at or prior to the Closing Date
of the following conditions:
(i) Seller shall have performed and complied with all covenants and
agreements contained in this Agreement and other Closing Documents that are
required to be performed and complied with by the Sellers on or prior to the
Closing Date, and the representations and
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warranties of the Seller contained in this Agreement shall be true as of the
date of this Agreement and as of the Closing Date;
(ii) There shall be no Encumbrances on the Distribution System except
as aforesaid in Subsection 6.2 hereof;
(iii) There shall not have occurred and be continuing any change or
changes in, or effect on, any of the property of the Distribution System that
is materially adverse to the assets, operations or condition of the Distribution
System;
(iv) The Seller shall have obtained all permits, approvals,
authorizations or consents from the proper agencies of the United States
government, including, without limitation, the United States Air Force and the
United States Department of Defense, for the consummation of the transactions
contemplated hereunder;
(v) The Buyer shall have received certificates from authorized officers
of the Seller, dated the Closing Date, to the effect that, to such officers'
knowledge, the conditions set forth in 8.2 (i), (ii), (iii) and (iv) have been
satisfied;
(vi) The Buyer shall have received an opinion from counsel for Seller,
dated the Closing Date, substantially to the effect that:
(a) Seller is duly organized, existing and in good standing under the
laws of the State of Maine and has the corporate power and authority to
execute and deliver this Agreement and consummate the transactions
contemplated hereby; and the execution and delivery of this Agreement and
the consummation and sale of the Distribution System contemplated hereby
have been duly authorized by all requisite corporate action;
(b) The execution and delivery and performance of this Agreement, or
any of the Closing Documents, by the Seller does not conflict with any of
its corporate authorizations or bylaws, as currently in effect, or
constitute a violation of or a default under any contracts related to the
Distribution System;
(c) The documents described in Section 4.3 are in proper form and
transfer to Buyer either (i) title to the Distribution System or (ii) an
exclusive and irrevocable leasehold interest in the Distribution System;
and, with respect to any interest in the Distribution System acquired by
the Buyer pursuant to (ii) of this paragraph (c), that the Seller has a
binding and valid obligation to transfer for no additional consideration,
title thereto to the Buyer once Seller has acquired title to said property;
and
(d) No declaration, filing or registration with, or notice to, or
authorization, consent or approval of any governmental authority is
necessary for the Seller's consummation of the Closing.
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8.3 Seller's
The obligation of the Seller to consummate the transactions contemplated
by this Agreement shall be subject to the fulfillment of or prior to the Closing
Date of the following additional conditions:
(i) The Buyer shall have performed in all material respects its covenants
and agreements contained in this Agreement which are required to be performed
on or prior to the Closing Date.
(ii) The representations and warranties of the Buyer that are set
forth in this Agreement shall be true and correct as of the date of this
Agreement and the Closing Date;
(iii) The Seller shall have received an opinion from counsel for the
Buyer, dated the Closing Date, substantially to the effect that:
(a) Buyer is duly organized, existing and in good standing under the
laws of the State of Maine and has the corporate power and authority to
execute and deliver this Agreement and consummate the transactions
contemplated hereby; and the execution and delivery of this Agreement and
the consummation and sale of the Distribution System contemplated hereby
have been duly authorized by all requisite corporate action;
(b) the execution and delivery and performance of this Agreement by
the Buyer does not conflict with any of its corporate authorizations or
bylaws, as currently in effect or constitute a violation of or a default
under any contracts related to the Distribution System; and
(c) No declaration, filing or registration with, or notice to, or
authorization, consent or approval of any governmental authority is
necessary for the Buyer's consummation of the Closing.
Article IX
Indemnification
9.1 Indemnification
(a) The Seller will indemnify, defend and hold harmless the Buyer from and
against any and all claims, demands or suits, losses, liabilities, damages,
obligations, costs and expenses (each, an Indemnifiable Loss) of any kind
asserted against or suffered by the Buyer relating to, resulting from or arising
out of (i) any breach by the Seller of any covenant or agreement of the Seller
contained in this Agreement or (ii) any excluded liabilities as set forth in
Section 2.2.
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(b) The Buyer will indemnify, defend and hold harmless the Seller from and
against any Indemnifiable Loss asserted against or suffered by the Seller
relating to, resulting from or arising out of any breach by the Buyer of any
covenant or agreement of the Buyer contained in this Agreement.
(c) Any person entitled to receive indemnification under this Agreement
having a claim under these indemnification provisions shall make a good faith
effort to recover all losses, damages, costs and expenses from such indemnitee's
insurers under applicable insurance policies so as to reduce the amount
of any Indemnifiable Loss hereunder. The amount of any Indemnifiable Loss shall
be reduced to the extent that the indemnitee receives any insurance proceeds
with respect to an Indemnifiable Loss.
(d) The expiration or termination of any covenant or agreement shall not
effect the parties' obligations under this Section 9.1 if the indemnitee
provided the indemnifying party with proper notice of the claim or amount for
which indemnification is sought prior to such expiration or termination.
(e) The rights and remedies of the Buyer and Seller under this Article IX
are exclusive and in lieu of all other rights and remedies that the parties may
have under this Agreement or otherwise for monetary relief with respect to any
breach or failure to perform any covenant or agreement set forth in this
Agreement; provided, however, that nothing herein shall abridge, modify, or may
in any way affect any right or remedy Buyer may have, or may in the future
acquire, under or on account of Title X, Section 1002 of the United States Code,
or any replacement or successor thereof..
(f) The parties each agree that notwithstanding any provisions in this
Agreement, both parties to this Agreement retain their remedies at law or in
equity with respect to willful,knowing or intentional breaches of this Agreement
or any covenant hereunder.
9.2 Defense of Claim
(a) Promptly after receipt by either party of any notice of the
commencement of any action or administrative or legal proceeding made or bought
by a person who is not a party to this Agreement (a Third Party Claim) as to
which the indemnity provided for herein may apply, such party shall notify the
other party in writing of such fact. The indemnifying party shall, at
the other party's request, assume the defense thereof with counsel designated
by the indemnifying party and satisfactory to the indemnitee. Nothing herein
shall prevent the indemnitee from employing, at its own expense, counsel with
respect to the matter as to which the indemnity provided for herein may apply.
The indemnifying party shall pay all costs that may be incurred by the
indemnitee in enforcing any provision for indemnification contained in this
Agreement.
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(b) If the indemnifying party fails to assume the defense of any Third
Party Claim covered by this indemnity, the indemnitee may, at the expense of the
indemnifying party contest (or, with the written prior consent of the
indemnifying party, settle) such Claim, provided that no such consent need be
made and settlement or full payment of any such claim may be made without
consent of the indemnifying party (with such party being obligated to indemnify
the indemnitee), if in the opinion of counsel of the indemnitee, such claim is
meritorious.
(c) Any claim by an indemnitee on account of an Indemnifiable Loss that
does not result from a Third Party Claim will be asserted by giving the
indemnifying party prompt written notice thereof, stating the nature thereof in
reasonable detail and indicating the estimated amount, if practicable, and the
indemnifying party will have 30 days within which to respond to such claim. If
the indemnifying party does not respond within such 30 days the indemnifying
party shall be deemed to have accepted such claim. If the indemnifying party
rejects such claim, the indemnitee may seek enforcement of its rights to
indemnification under this Agreement.
Article X
Termination and Abandonment
10.1 Termination
(a) This Agreement may be terminated at any time prior to the Closing Date
by mutual written consent of the parties.
(b) This Agreement may be terminated by either party if the Closing shall
not have occurred on or before the first anniversary of the date of this
Agreement; provided that this right to terminate shall not be available to a
party whose failure to fulfill any obligation under this Agreement has been
the cause of, or resulted in, the failure of the Closing to occur.
(c) This Agreement may be terminated by a non-breaching party if there has
been a material violation or breach by the other party of any agreement,
representation or warranty contained in this Agreement that has rendered
impossible the satisfaction of any condition to the obligations of the non-
breaching party.
10.2 Effect of Termination
If this Agreement is terminated as provided herein, such termination shall
be the sole remedy of the parties hereto with respect to breaches of any
agreement, representation or warranty contained herein and neither of the
parties nor any of their respective trustees, directors, officers or employees,
as the case may be, shall have any liability or further obligation to
the other party or any of their respective trustees, directors, officers or
employees, as the case may be, pursuant to this Agreement.
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Article XI
Miscellaneous Provisions
11.1 Amendment and Modification
This Agreement may be amended, modified or supplemented only by written
agreement of the parties.
11.2 Notices
All notices and other communications hereunder shall be in writing and
shall be deemed given and received if delivered personally or by facsimile
transmission or mailed by U.S. mail (return receipt requested), postage prepaid,
to the parties at the following addresses:
(a) If to the Seller, to
Loring Development Authority of Maine
P.O. Box 457
Limestone, Maine 04750-0457
Fax: (207) 328-6811
Attention:
(b) If to the Buyer, to
Maine Public Service Company
P.O. Box 1209
Presque Isle, Maine 04769-1209
Fax: (207) 764-6586
Attention: Stephen A. Johnson
11.3 Assignment
This Agreement and all of the provisions hereof shall be binding upon and
inure to the benefit of the parties hereto and their respective successors and
permitted assigns, but neither this Agreement nor any of the rights, interests
or obligations hereunder shall be assigned by any party hereto, including by
operation of law, without the prior written consent of the other party, nor is
this Agreement intended to confer upon any other person except the parties
hereto any rights or remedies hereunder.
11.4 Governing Law
This Agreement shall be governed by and construed in accordance with the
laws of the State of Maine as to all matters.
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11.5 Interpretation
The article and certain headings contained in this Agreement are solely for
the purpose of reference and shall not in any way affect the meaning or
interpretation of this Agreement.
11.6 Exhibits
All Exhibits referred to herein are intended to be and hereby are
specifically made a part of this Agreement.
11.7 Entire Agreement
This Agreement embodies the entire understanding and agreement of the
parties in respect to the transactions contemplated by this Agreement. There
are no restrictions, promises, representations, warranties or covenants other
than those expressly set forth herein. This Agreement supersedes all
prior agreements and understandings between the parties with respect to such
transactions.
IN WITNESS WHEREOF, the parties have caused this Agreement to be signed by
their respective duly authorized officers as of the date first above written.
LORING DEVELOPMENT AUTHORITY OF MAINE
Witness /s/ Carl W. Flora By /s/ Brian N. Hamel
Name: Brian N. Hamel
Title: President & CEO
MAINE PUBLIC SERVICE COMPANY
Witness /s/ Carl W. Flora By /s/ Stephen A. Johnson
Name: Stephen A. Johnson
Title: Vice President and General Counsel
PSLoring.saj
Exhibit 99(q)
STATE OF MAINE Docket No. 97-670
PUBLIC UTILITIES COMMISSION
February 20, 1998
MAINE PUBLIC SERVICE COMPANY ORDER
Divestiture of Generation Assets
WELCH, Chairman, NUGENT and HUNT, Commissioners
_________________________________________________________________
I. SUMMARY
We approve Maine Public Service Company's (MPS or the
Company) plan to divest the Company's generation assets. We do
not modify MPS's plan to sell its assets to the highest bidder,
because the bid process is reasonable and MPS may reject the bids
for any or all of the generation assets. In evaluating bids, MPS
should consider the risks and benefits associated with selling
its Tinker Generating Station and the market power concerns
described in this Order.
II. BACKGROUND AND PROCEDURAL HISTORY
The MPS electrical system is strengthened by
interconnections with New Brunswick, Canada, which allow
electrical support from the New Brunswick Power Corporation (NB
Power). However, unlike Central Maine Power Company (CMP) and
Bangor Hydro-Electric Company (Bangor Hydro), MPS is electrically
isolated from the area controlled by the Independent System
Operator-New England (ISO-NE) and must move power through NB
Power and Maine Electric Power Company (MEPCO) to transact within
ISO-NE. The transmission capacity between MPS and NB Power is
200 MW when all lines are in service and 72 MW if a line is out
of service. From an economic perspective, the ability to sell
across New Brunswick is further limited because, while NB Power
does have open transmission access, access is obtained at
relatively high transmission rates.
All MPS transactions into the area controlled by ISO-NE are
wheeled through New Brunswick and then over the MEPCO
transmission line. According to MPS, the Company could deliver
as much as 100 MW or as little as 0 MW to ISO-NE, depending upon
the status of generating units and transmission lines in Canada.
For stability purposes, sales north to south have historically
been required to enable MPS to make purchases from the south.
However, there are severe limitations on the ability to import
power from the area controlled by ISO-NE into MPS's territory
because of constraints on the MEPCO line. Given the cessation of
ORDER -2- Docket No. 97-670
stability flows in 1997, firm power cannot now be purchased from
the south. Non-firm power can be purchased when other factors
that affect the MEPCO line, such as load in New England,
generation in Maine and other flows on the MEPCO line, allow.
With the passage of "An Act to Restructure the State's
Electric Industry" (the Restructuring Act), MPS is required, with
certain exceptions, to divest all generation assets and all
generation-related business activities by March 1, 2000. P.L.
1997, c. 316 enacting 35-A M.R.S.A. s. 3204(1). The Restructuring
Act requires the divestiture to be accomplished according to a
plan submitted to the Commission for review. The divestiture of
generation assets is important both to ensure effective
competition and to value generation assets for purposes of
measuring stranded costs.
On September 9, 1997, MPS filed its plan to divest its
generation assets. Under its plan, MPS is offering to sell its
generation assets and power entitlements to an unaffiliated buyer
for cash consideration. MPS has begun soliciting bids and
expects to complete the process by April 10, 1998. MPS has hired
Stone and Webster Management Consultants, Inc. to assist the
Company in its sale efforts. Stone and Webster was selected
because of its experience with generating sale activities in New
England and California, as well as its familiarity with the
Company.
MPS has a total of 109.8 MW of generation resources
including 35.8 MW of hydro-electric and 55.9 MW of thermal
resources. The specific assets offered for sale are:
- Millinocket Lake Storage Dam;
- Squa Pan Dam, including storage and 1.4 MW of
hydro-electric generating capacity;
- Caribou Generating Station, consisting of 23.0 MW of
oil fired steam capacity, 7.0 MW of diesel capacity and
0.9 MW of hydro-electric capacity;
- 4.2 MW of diesel power at Flo's Inn Generating Station
and a dismantled diesel unit at Houlton Generating
Station;
- A 3.3455% interest, equivalent to 20.7 MW, in the Wyman
Unit No. 4 oil fired thermal plant in Yarmouth, Maine;
- Rights to the output of a 18.1 MW biomass plant
currently under a purchased power agreement between
ORDER -3- Docket No. 97-670
Wheelabrator-Sherman Energy Company (Wheelabrator Sherman
or W/S) and MPS;
- 34.5 MW Tinker Station, which includes 33.5 MW of
hydro-electric capacity and 1 MW of diesel capacity.
The Tinker Station is located on the Aroostook River in
Aroostook Junction, New Brunswick, across the border from Fort
Fairfield, Maine. The Tinker Station is owned and operated by a
wholly-owned subsidiary of MPS, Maine and New Brunswick
Electrical Power Company, LTD. The properties of MPS and the
subsidiary are operated as a single integrated system. The
subsidiary sells to MPS the energy not needed to supply the
subsidiary's wholesale New Brunswick customer, the Town of
Perth-Andover. The Perth-Andover contract is a full requirements
contract. The contract term is through December 31, 2004, and is
automatically renewed every 5 years unless and until either party
gives the other written notice to terminate the contract. The
Perth-Andover sales for 1996 were 29,551 MWH with a peak load of
8.4 MW. The subsidiary also owns transmission assets connecting
the Tinker Station to the MPS service territory and an
interconnection with NB Power. The Tinker Station is being
offered in three options:
- purchase 100% ownership of the subsidiary, including
the generation, transmission and other assets;
- purchase only the generation assets, the Tinker
Generating Station;
- purchase only the rights to the output of the Tinker
Station.
The Company states that its goal in selling its assets is to
maximize the sale price and thereby reduce the Company's stranded
costs. The Company is using a public bidding process to solicit
bids from a large number of potential bidders, both in the United
States and Canada. Its first step was to issue a "teaser"
letter. Interested bidders were then sent an offering memorandum
which describes in more detail the generation assets being sold
and the transaction process. Bidders were invited to a data room
to inspect the Company's records on its generating assets and to
inspect the generating plants and storage dams. By October 27,
1997, bidders were required to submit a non-binding statement of
qualifications indicating their capabilities to operate and
maintain the generating assets and to consummate the transaction.
On November 10, 1997, MPS notified qualified bidders to commence
their due diligence activities with binding bids being due on
January 15, 1998. Qualified bidders were determined based on
ORDER -4- Docket No. 97-670
their financial and technical qualifications. MPS intends to
complete negotiations with the bidders by April 10, 1998. The
Company intends to select the bid or combination of bids that
maximizes sale revenue and minimizes stranded cost resulting from
the divestiture. Bidders have the option of offering the sale of
the output of the sold plants back to MPS through February 29,
2000.
Timely petitions to intervene were filed on behalf of the
Public Advocate and Wheelabrator-Sherman. Late filed petitions
to intervene were filed on behalf of Tractebel Energy Marketing,
Inc. and the Industrial Energy Consumer Group (IECG). All
petitions to intervene were granted. A hearing and oral argument
was held on December 18, 1997, in which the testimony of Company
witnesses Fred Bustard, David Holabird and Timothy Brown was
heard. Mr. Bustard explained that the Company had recently
contracted for replacement energy and capacity with two entities,
Alternative Energy, Inc. (AEI) (1) and Hydro-Quebec (HQ). The
contract with AEI provides MPS with the ability to meets its load
requirements in excess of the amount served by the combined
output of the Tinker Station and the Wheelabrator-Sherman
contract. The Hydro-Quebec contract allows the actual amount of
power delivered to vary widely, up to 130MW. MPS has also
entered into a marketing agreement with Cinergy Corporation of
Ohio whereby Cinergy will market surplus energy acquired by MPS
under the Hydro-Quebec and AEI contracts. By taking up to the
maximum output pursuant to the Hydro-Quebec contract, MPS could
fully replace the output associated with the generating assets
presently for sale.
III. REVIEW OF MPS'S PLAN
MPS's divestiture plan is adequate, consistent with the
Restructuring Act and reasonable on its face. (2) In general,
MPS's divestiture plan bears a strong resemblance to the plans
developed by other utilities in New England including New England
Electric System (NEES), Boston Edison, Eastern Utilities
Associates, and Central Maine Power Company.
ORDER -5- Docket No. 97-670
A. Plan Development and Design
Overall, the components of MPS's plan, including the
offering memorandum, information distribution and scheduling, are
adequate. Principal elements of the asset divestiture process
include selection of an advisor, development of a marketing
strategy, packaging the assets and formulating a bid procedure,
advertising or marketing to potential purchasers, and comparison
of other divestiture options.
MPS began its process with the selection of Stone and
Webster as its advisor. Unlike other companies such as CMP and
NEES, MPS did not retain an investment banker. Given the small
size of MPS's assets, the similarity of MPS's plan as compared to
other companies, and the importance of transmission constraints
in evaluating its assets, MPS's decision to proceed without an
investment banking firm is reasonable.
MPS used a single bid process. The interest-building
component of MPS's plan began with a series of public
announcements about the sale. MPS developed a list of potential
bidders it believed had genuine interest in the assets and
contacted them. The targeted bidders were also advised that an
offering memorandum and a document center were available.
With the possible exception of omitting details regarding
the status and provisions of the Wheelabrator-Sherman contract,
MPS's Offering Memorandum contains information that is adequate
for potential bidders to make a decision regarding the
seriousness of their interest in MPS's assets. The data are
complete and presented in an objective manner, emphasizing the
strengths of the asset offerings but disclosing relevant
information concerning potential weaknesses. The additional
information resources made available also appear consistent with
industry practice. The availability of MPS's information room
and due diligence opportunities are clearly disclosed and are
subject to reasonable confidentiality restrictions. MPS's
proposed time frame is consistent with the periods within which
the sale processes of CMP, NEES and Boston Edison were completed.
MPS's one-bid sale process is adequate in light of the
size of the MPS asset portfolio. MPS granted an extension at the
request of one party so that binding proposals were due January
15, 1998 instead of December 8, 1997. MPS's delay in the process
to accommodate additional bidding is reasonable to take advantage
of opportunities to maximize value for ratepayers.
Based on statements in the oral argument, MPS appears to
have been successful in soliciting bidders from other New England
ORDER -6- Docket No. 97-670
sale processes as well as potential Canadian purchasers. Coupled
with the extensive publicity that accompanied the mandated
divestitures in New England, most potential bidders were likely
aware of the proposed asset sales. MPS did not discuss the
option of an asset-by-asset auction as an alternative strategy in
selling its generating assets. Like CMP, MPS bundled its
generation assets into packages defined by type of facility. All
facilities of a given type -- fossil, hydro, and power purchase
agreements -- are offered as a group. (3) However, because MPS's
assets are small both in number and aggregate capacity, its
bundling is almost equivalent to an asset-by-asset sale.
As to other means for divestiture, MPS addressed the
possibility of a generation subsidiary spin-off during oral
argument. Counsel for MPS stated that a spin-off would not be
beneficial because of high transaction costs, market perceptions
of value and environmental issues. We agree that transactions
costs for an entity the size of MPS would likely be
disproportionate and render the option uneconomic. Consequently
we do not address the other reason cited by MPS for rejecting a
spin-off.
B. Timing of the Sale of Generating Assets
MPS has proposed to proceed immediately with
implementation of its plan for selling its generation assets.
MPS has proposed a schedule that will allow it to complete its
divestiture transactions before the end of 1998. From
ratepayers' perspective, timing issues are different for the
various MPS generation assets.
1. Wyman
Timing issues for Wyman involve ensuring that MPS has
the option to sell its share of Wyman as part of CMP's
divestiture of its Wyman ownership. Therefore timing of MPS's
sale of Wyman depends upon the CMP process. Given that CMP is
going forward now, MPS's desire to sell Wyman during a similar
time frame is reasonable.
2. Aroostook County Fossil and Hydro Plants
Timing issues associated with the plants physically
located in Aroostook County are not significant from a ratepayer
perspective because these plants produced only 1% of MPS's energy
in 1996. All MPS-owned fossil and hydro plants physically
located in Aroostook County are small and old. Pursuant to
ORDER -7- Docket No. 97-670
statute, MPS must divest these plants prior to March 1, 2000.
For these assets, a sale in 1998 rather than 2000 would not have
a significant impact on MPS's stranded costs or on the
development of competitive markets.
3. Tinker
The Restructuring Act does not require that MPS divest
the Tinker Station, because Tinker is located outside of the
United States. The Act does require MPS to sell at least its
entitlement to the output of Tinker after February 28, 2000, in
accordance with Commission rules. (4) In recognition of this
exception, MPS has offered potential buyers three options for
Tinker: (1) purchase of its subsidiary, Maine and New Brunswick
Electrical Power Company, Ltd, which includes Tinker Station
generating assets, as well as transmission assets; (2) purchase
of the Tinker Station generating assets only; and (3) purchase of
the output of the station for a period selected by the bidder.
Thus, MPS has retained sufficient flexibility to sell the
physical assets if a high enough bid is received. If MPS does
not receive a sufficiently attractive bid, it could sell the
entitlement to Tinker capacity and energy for a relatively short
time period, and then either rebid this entitlement or sell the
physical assets.
A final sale of MPS's Tinker assets now could limit
flexibility in the event retail markets do not develop in MPS's
territory. As discussed further in this Order, the market
structure and likely market conditions of MPS's territory will be
different, and may be constrained, relative to territories in
NEPOOL. Moreover, a final sale of the Tinker assets now would
lock in the associated market value and stranded cost and expose
MPS's ratepayers to the risk of market prices rising.
In any subsequent case in which MPS seeks our approval
for a sale of Tinker, we will consider the following questions:
1. Would a delay in the sale of the Tinker
Station assets likely benefit ratepayers through
realization of a higher sales price once retail
markets develop in Canada?
2. Should Tinker Station be used as a hedge for
ratepayers, by selling only entitlements to its
output for relatively short time periods to
protect against the contingency that competitive
ORDER -8- Docket No. 97-670
markets do not develop in northern Maine because
of its electric isolation?
3. Should any final decision on the disposition
of Tinker Station be delayed until the Commission
has completed its study involving transmission
capacity to northern Maine and the efficacy of
competitive markets in the region?
We expect MPS to consider these issues as it
proceeds and address each in any subsequent filing for sale
approval. We discuss each issue in more detail below.
a. Delay selling Tinker assets
Unlike plants in the area controlled by
ISO-NE (such as Wyman) where deregulated markets will soon
develop and where retail demand will exist for energy and
capacity produced by the plant, the sale market for Tinker's
output is uncertain. Unless a high price can be realized for
Tinker, ratepayers may be better off if MPS sells entitlement to
the output for a relatively short-term period, and sells the
physical assets at a later date when markets are more developed,
or more certain.
At present, energy sales from the Tinker
Station into the emerging markets in the area controlled by
ISO-NE would be constrained by both physical and economic, or
institutional, factors. The physical constraints are the limits
discussed earlier regarding flows over the MEPCO line. Economic
or institutional factors arise because the plant is outside of
the area controlled by ISO-NE and its cost must include an adder
for transmission that competing plants located in ISO-NE do not.
If the most likely markets for the output of
Tinker are the markets in Canada and Aroostook County, the size
of the retail market and the effect of transmission costs may
depress Tinker's value. Selling into Canadian markets from
Tinker primarily involves constraints related to development of
retail markets, as well as high transmission rates. At present,
Tinker cannot be sold into retail markets in Canada by any
supplier except an existing Canadian utility. According to MPS,
retail access in Atlantic Canada is a minimum of five years away.
Therefore, if Tinker's output is sold in Canada by any entity not
a Canadian utility, it would be only into wholesale markets.
Further, there may be market limitations even at the wholesale
level because of high transmission rates across New Brunswick.
Currently, NB Power's transmission rate is $40/KW/year.
Transmission costs at such a high level could make it difficult
for Tinker to compete in Canadian wholesale markets.
ORDER -9- Docket No. 97-670
NB Power itself could be a potential market
for the Tinker power on a wholesale basis. However, a review of
1996 data demonstrates that this may not be a very attractive
option. MPS sold 19,743 MWh to NB Power at an average price of
only $11.40/MWh. Even if this price primarily represented
surplus off-peak energy, the price is low compared to NEPOOL
prices for similar energy.
The final option for Tinker output is
northern Maine, comprising primarily MPS's service territory.
MPS must continue to supply the capacity and energy needs of its
customers prior to retail access and, after retail access,
deliver electricity to its current customers as direct retail
purchasers. Prior to March, 2000, sales opportunities into
northern Maine could be limited because of the surplus resulting
from MPS's contracts with Hydro-Quebec and AEI. Without any
significant market in northern Maine for Tinker, particularly in
the near term, its full value might not be realized by a sale at
this time.
b. Use of Tinker as a ratepayer hedge
Unlike the situation in the CMP divestiture,
where its customers and assets will be part of the ISO-NE market,
the development of functional competitive markets is less certain
in northern Maine. Given this uncertainty, it is possible that
ratepayers would benefit if MPS proceeded cautiously, selling
Tinker entitlements for relatively short periods rather than
selling the assets now. This would allow a future evaluation of
how actual markets are operating in the region. If markets are
not functioning in an effectively competitive manner, Tinker
would remain available to MPS ratepayers.
If competitive markets do not develop in
northern Maine, MPS ratepayers could face a situation whereby
potential suppliers (then unregulated) possessed market power.
As discussed previously in this Order, such factors as severe
transmission constraints and economic and institutional barriers
indicate the market conditions for customers in northern Maine
may be different and, perhaps, less advantageous than for
customers in other parts of the State. MPS and the
consumer-owned utilities in northern Maine are a small part of a
market over which Maine has incomplete control. (5) Proceeding
ORDER -10- Docket No. 97-670
cautiously in implementing the policies embodied in the
Restructuring Act, such as to delay final sale of the Tinker
assets, could provide a hedge for ratepayers while a competitive
market develops in the region. Once it is clear that the market
is functioning with competitive prices available to ratepayers in
northern Maine, Tinker could be divested.
We have not concluded at this point that MPS
should delay sale of the Tinker assets. At such time MPS
proposes to divest Tinker we will address the question of whether
the timing and form of its proposed divestiture maximize Tinker's
value and adequately protect MPS's ratepayers from the risks
discussed herein.
c. Sale of Tinker before the market power study
and the northern Maine transmission study
Divesting the Tinker Station assets now could
also limit the Commission's flexibility to fashion solutions to
issues which might arise in the market power study and northern
Maine market viability study, both of which the Commission is
currently conducting at the direction of the Legislature. (6)
Selling the Tinker assets now would foreclose a significant
opportunity for adjustments in policy or implementation with
respect to retail competition for the portions of Maine that are
not part of the area controlled by ISO-NE.
C. MPS's Proposed Sale of Wheelabrator-Sherman Capacity
and Energy
The Restructuring Act directs investor-owned utilities
in Maine to sell their entitlements to capacity and energy from
power contracts as of March 1, 2000. For MPS, this means it must
sell its entitlement to capacity and energy from the
Wheelabrator-Sherman facility. Although not required by statute,
MPS has included this sale as part of its divestiture plan at
issue in this proceeding. As part of its divestiture process,
MPS has requested bids on W/S and asked bidders to propose the
purchase term.
We addressed this issue generally in our Order
approving CMP's divestiture plan issued January 14, 1998 in
Docket No. 97-523. As we stated in that case, selling the output
of purchased power contracts through their term, or for long
periods at a time, represents a risk to ratepayers. In contrast,
a short term sale coupled with subsequent re-bids provides a
ORDER -11- Docket No. 97-670
hedge to ratepayers against increasing market prices as well as
problems, perhaps unique to MPS and the northern Maine COUs, with
market development. Short-term bids for the W/S output may also
be affected less than longer term bids would be by uncertainty
arising from Wheelabrator-Sherman's ability to close the plant at
its sole discretion. (7) We also note a concern about a sale of W/S
output during the pre-March 1, 2000 period due to the presence of
MPS's purchase contract with HQ. During the pendency of the HQ
contract, it is difficult to see any advantage to such a sale.
Specifically, if a purchaser bids a price less than the HQ
effective price, MPS would be better off not selling but
retaining W/S and reducing HQ purchases. On the other hand, no
bidder would rationally bid more than the HQ price because it
would likely have to resell the power at prevailing market
prices, which as discussed in the attached consultant's report,
will be driven by the HQ contract.
As in our decision approving CMP's divestiture plan,
these concerns do not cause us to reject MPS's plan. However,
MPS should be cognizant of these issues as it goes forward. At
the time MPS proposes to sell its entitlement to W/S capacity and
energy, we will evaluate whether the form and timing of its
proposed sale is reasonable.
D. Market Power
1. Generation Market
In our approval of the CMP divestiture plan, we
concluded that a sale of generating assets that results in
opportunities for the exercise of market power would be contrary
to the goals of the Restructuring Act. However, we also
concluded that concern that the ultimate sale may result in
market power is not grounds to reject the divestiture plan. We
reach the same conclusion for MPS's divestiture plan. We express
again our serious concern that the sale of utility assets not
result in concentration of market power to the detriment of Maine
consumers. We will closely scrutinize any proposed asset sale
MPS presents to ensure such concentration does not arise or is
not significantly worsened by the manner in which Maine's
generation assets are divested.
The factors that define MPS's market structure and
the issues relevant to market power are different for MPS than
for CMP. Market structure is initially defined by the physical
ORDER -12- Docket No. 97-670
characteristics of available generation and transmission. We
described the constraints that affect the import and export of
power between ISO-NE and the New Brunswick-northern Maine region
above. Although there is adequate transmission capacity across
the MPS-New Brunswick interconnection to serve most (if not all)
of the load requirements of northern Maine from supply outside
the region, constraints on the MEPCO line and economic and
institutional factors, primarily in New Brunswick, effectively
render northern Maine a distinct market area for purposes of
market power analysis.
The relevant market is further defined by the
number and size of the competitors in that market. Although Nova
Scotia Power Corporation and Hydro-Quebec can physically deliver
power to northern Maine, NB Power's relatively high transmission
rates and its apparent ability to increase those rates
unilaterally make the long term participation of those two
entities in the northern Maine market uncertain. The other
competing suppliers are NB Power, the future owner(s) of the
assets and contracts now owned by MPS, the owner of Aroostook
Valley Electric Company (AVEC), and AEI. Competitors on the
Canadian side of the interface can physically deliver up to 200
MW of power to MPS's territory, i.e. the tie limit. Competitors
on the Maine side can each offer lesser amounts.
Given the size of NB Power's resources in this
market, together with its control of the gateway, there are
market power concerns that go beyond what the Commission could
affect in the context of MPS's divestiture. Nonetheless, the
divestiture may present us with a unique opportunity to ensure
that an already high market concentration go no higher. In
addition, MPS's divestiture presents us with an opportunity to
examine whether strategies to decrease the concentration, such as
by splitting up MPS's assets among more than one buyer, would be
beneficial.
In a market as small as the one considered here,
even small changes in market concentration, especially accretions
to market share by one of only a few market participants, may be
significant. Thus, sale of one or more of MPS's assets to a
participant currently in-market could make an already highly
concentrated market significantly more so. A sale of all MPS's
assets or entitlements to a single buyer not currently in-market
would simply perpetuate the existing level of market
concentration. A sale of the principal MPS supply entitlements
(the Tinker and Wheelabrator-Sherman contracts) to separate
entities not currently in market could increase the number of
suppliers and lessen concentration in the market.
ORDER -13- Docket No. 97-670
2. Renewables Market
The Act requires that 30% of the supply resources
for each competitive provider be derived from renewable sources.
This requirement effectively defines a separate product market
for renewables. Because the structure of the renewables market
is unclear at this point, we discuss market power in a renewables
market defined similarly to MPS's generation market, and one that
also includes the area controlled by ISO-NE.
MPS currently controls a significant portion of
the available renewable supply in northern Maine. If the
renewable market is defined by supply in northern Maine, sale of
all of MPS's renewable assets in one bundle would simply transfer
this market share to the buyer. If the relevant market for
renewables is broader, including other New England and Canadian
suppliers, our concern will be whether a proposed purchase of one
or more of MPS's renewable assets would cause an unacceptable
increase in market concentration. This could occur if, for
example, a current in-market participant with an already large
share of the renewable supply proposed to purchase MPS's
renewable assets, or W/S's output. We will examine market power
in the renewables market at the time MPS proposes to sell one or
more renewable asset or contract.
IV. CONCLUSION
MPS's divestiture plan is approved. MPS shall proceed to
divest its generation assets in accordance with this plan, and in
a manner that addresses the concerns raised by the Commission in
this Order.
Dated at Augusta, Maine, this 20th day of February, 1998.
BY ORDER OF THE COMMISSION
/s/ Dennis L. Keschl
Dennis L. Keschl
Administrative Director
COMMISSIONERS VOTING FOR: WELCH
NUGENT
HUNT
(1) AEI owns a 37 MV generation facility in Ashland, Maine.
(2) The Commission has relied, in part, on the report of Econsult Corp., the
Commission's consultant in this proceeding, to identify issues we are likely to
address in the next phase. The Commission considers that report to be a sound
articulation of the issues that the Commission should consider. Except to the
extent stated in this Order, however, the Commission neither endorses nor
disputes any of the conclusions set forth in that report. We attach a redacted
copy of the consultant's report to this Order.
(3) The Tinker Hydro-Electric Station includes 1 MW of diesel generation.
(4) See 35-A M.R.S.A. s. 3204(1)(c) and s. 3204(4).
(5) The northern Maine area is mainly Aroostook County. The relevant market
includes northern Maine and parts of Canada. The Maine portion of this market
is roughly one and one-half times MPS's load, and includes MPS, Eastern Maine
Electric Cooperative, Houlton Water Company (Electric Department), and Van Buren
Light & Power District.
(6) See 35-A M.R.S.A. s. 3206 and P.L. 1997, ch. 447.
(7) The revised Agreement between MPS and W-S would allow W-S to suspend its
performance under the Agreement upon 30 days notice. This Agreement was
recently approved by the Commission in Docket 97-727. Approval of the Finance
Authority of Maine is pending.
Exhibit 99(r)
STATE OF MAINE Docket No. 98-138
PUBLIC UTILITIES COMMISSION
September 2, 1998
MAINE PUBLIC SERVICE COMPANY ORDER
Request for Approval of Reorganization
Approvals and Exemptions and For Affiliated
Interest Transaction Approvals
WELCH, Chairman; NUGENT, Commissioner
_____________________________________________________________________
I. SUMMARY
In this Order, we grant Maine Public Service Company's (MPS) petition for
reorganization approvals and exemptions, and for certain affiliated interest
transactions related to the formation of a wholly-owned energy marketing
affiliate, subject to conditions discussed below. We reject the request for
approval that would allow the marketing subsidiary to publicize its affiliation
with MPS.
II. BACKGROUND
On February 18, 1998, Maine Public Service Company (MPS) filed a petition
for reorganization approvals and exemptions pursuant to 35-A M.R.S.A. s. 708 and
for the approval of certain affiliated transactions pursuant to 35-A M.R.S.A.
s. 707. As explained in its petition, MPS is seeking approval pursuant to 35-A
M.R.S.A. s. 708 for the formation of Energy Atlantic, LLC (EA) as a wholly-owned
subsidiary from which it will be able to perform various non-core activities,
such as retail and wholesale marketing of energy and capacity and the sale of
energy-related products and services. MPS is also requesting the authority to
invest up to $2 million in the subsidiary, which would include any loans or loan
guarantees by MPS to EA. Simultaneously, MPS requests Commission approval of
the following "affiliated interest" transactions pursuant to 35-A M.R.S.A. s.
707:
1) MPS's making or guaranteeing unspecified loans to EA, which together
with any capital contributions or investments, shall not exceed the $2
million cap requested under 35-A M.R.S.A. s. 708;
2) MPS and EA entering into a limited liability company operating
agreement, specifying the rights and duties of MPS as EA's sole member;
Order -2- Docket No. 98-138
3) MPS and EA entering into a management service agreement setting
forth the types of management services MPS will provide EA, how MPS
shall be compensated for these services, and how costs will be
allocated between the two companies; and
4) MPS and EA entering into an agreement with respect to certain
intangible assets, allowing EA to promote its affiliation with MPS and
providing for payment for the same.
Finally, MPS seeks an exemption from individual Commission reorganization
approvals that may be triggered, under 35-A M.R.S.A. s. 708), by each
contribution of capital or loan by MPS to EA. MPS asks for an exemption
pursuant to 35-A M.R.S.A. s. 708(2)(A), provided that the total of all such
loans or contributions of capital by MPS to EA shall not exceed $2 million.
On February 27, 1998, the Examiner issued a Notice of Proceeding and
Opportunity for Intervention. The Public Advocate petitioned for and was
granted intervention. The Public Advocate and the Advisory Staff conducted oral
and written discovery regarding the MPS petition. On June 17, 1998, the Public
Advocate filed written comments opposing the approval of the reorganization,
primarily due to the potential financial impact on MPS and its ratepayers, and
on MPS's unwillingness to accept the full financial consequences of its
investment. On July 1, 1998, the Advisory Staff submitted an analysis intended
to assess the financial condition and creditworthiness of MPS.
The Commission held a hearing in this matter. During the hearing, MPS
presented the testimony of Calvin Deschene and Larry LaPlante in support of the
reorganization. During oral argument, the Public Advocate stated that, if the
financial risk of the investment were placed solely an shareholders, he would
not oppose the proposed reorganization.
III. DISCUSSION
A. Statutory and Regulatory Criteria
Section 708 of Title 35-A governs reorganizations of public utilities.
Section 708 states that no reorganization may be approved unless it is
established by the applicant that the reorganization is consistent with the
interest of the utility's ratepayers and investors. Section 708 further states
that in granting an approval, the Commission shall impose such terms, conditions
or requirements that are necessary to protect ratepayers including, among other
things, provisions which ensure:
Order -3- Docket No. 98-138
- that the utility's ability to attract capital on reasonable
terms, including the maintenance of a reasonable capital
structure, is not impaired;
- that the ability of the utility to provide safe, reasonable
and adequate service is not impaired;
- that the utility's credit is not impaired or adversely
affected; and
- that reasonable limitations are imposed upon the total
level of investment in non-utility businesses.
35-A M.R.S.A. s. 708(2)(A). Additionally, section 713 of Title 35-A specifies
that a utility may not charge its ratepayers for costs attributable to
unregulated business ventures.
These statutory provisions express a legislative directive that utility
diversification into unregulated businesses be approved only upon a
demonstration that the utility's core activities will not be jeopardized. The
concern is that investments in unregulated businesses may have negative
financial consequences, such as increasing the costs of debt and equity, that
could impact the utility's ability to provide service on reasonable terms. The
Legislature also sought to preclude ratepayer subsidy of unregulated businesses,
as well as any unfair competitive advantages that may result from an affiliation
with a utility.
To implement these legislative policies and directives, the Commission
recently promulgated Chapter 820, which contains rules to govern non-core
activities and transactions between affiliates. In adopting these rules, the
Commission reaffirmed its policy that ratepayers should be completely insulated
from the financial impacts of utility investments in non-core activities. Order
Provisionally Adopting Rule, Docket No. 97-886 at 16-17 (Feb. 18, 1998). To
achieve this policy goal, Chapter 820 states that utilities may invest up to a
specified cap without Commission review if the utility has an investment grade
credit rating. A utility with a below-investment grade rating, with some
exceptions, is not permitted to make an investment in a non-core activity.
Chapter 820 adopts the utility's credit rating as the standard for allowing
investments because such ratings are a reliable indicator of a utility's
financial health. Id. at 38. If a utility is in weak financial condition, it
becomes much more difficult, if not impossible, to insulate ratepayers from the
financial consequences of a non-core investment. For example, an unsuccessful
investment by a financially weak utility may result in a breach of a loan
covenant under
Order -4- Docket No. 98-138
circumstances in which rate increases may be the only alternative to bankruptcy.
The rationale underlying Chapter 820's provision is that a utility with a
non-investment grade bond rating is not financially sound and, as a result,
there is a reasonable likelihood that the Commission would not be able to
fulfill its fundamental policy of protecting ratepayers from the consequences
of non-core activities.
Chapter 820 also seeks to protect ratepayers from subsidizing non-core
activities and prevent unfair competitive advantages by establishing specific
affiliate transaction and accounting rules. These rules require utilities and
affiliates to charge each other market rates for goods and service that are not
tariffed. To the extent a market price is unavailable, Chapter 820 requires the
utility to charge its affiliate based on a fully distributed cost methodology.
Ch. 820 s. 4.
B. MPS Financial Condition
The primary issue in this proceeding is whether the financial condition
of MPS is sound enough to allow for the approval of its request to invest up to
$2 million in EA. MPS is not currently rated by any of the major bond rating
agencies. Therefore, MPS does not have a credit rating that would allow us to
directly implement the provisions of Chapter 820 as discussed above. (1) The
lack of a credit rating, however, does not alter the basic conclusion that a
utility must be in sound enough financial condition to insulate ratepayers from
the consequences of non-core investments. Under these circumstances, we must
independently assess MPS's financial condition to determine whether to approve
its investment in EA.
This matter must be scrutinized carefully because MPS has, in the
recent past, endured serious financial difficulties. The Company's financial
problems, due primarily to the shutdown of Maine Yankee, led to a violation of
its debt covenants resulting in a significant increase in its debt costs.
Additionally, the depressed level of MPS's earnings during 1997 triggered the
earnings-sharing provision of its rate plan, contributing to a significantly
higher rate increase in 1998 than the amount pre-established under the terms of
the plan.
To assess the Company's financial condition, our Advisory Staff
analyzed MPS's financial capacity by using statistical and ratio analysis to
approximate a bond rating. The results of that analysis were mixed, indicating
that the Company is borderline as to whether it would be of investment grade
quality. For this reason,
(1) Chapter 820 provides that if a utility does not have a credit
rating, review of the reorganization occurs pursuant to 35-A M.R.S.A.
ss. 707, 708. Ch. 820, s. 5(C).
Order -5- Docket No. 98-138
the decision of whether to approve the investment is an extremely
difficult one. After careful consideration, we will allow MPS to proceed with
its investment upon the condition, and with the complete understanding, that
ratepayers will not be subject to any additional costs that may result from the
investment.
To enforce this condition, we intend to scrutinize any future rate
request to ensure that ratepayers are held completely harmless. MPS is under
a permanent obligation to demonstrate in any rate proceeding that no part of a
rate request is caused by its investment in EA. (2) If MPS cannot make such
a showing, we will reduce the amount of the rate change accordingly to ensure
that ratepayers have been insulated from the investment. (3) Moreover, we will
not allow ratepayers to pay for any additional interest costs resulting from a
debt covenant violation that is caused in whole or in part by the investment;
neither will we allow an increase in rates to maintain or place the utility in
compliance with its debt covenants if the violation or potential violation is
a direct or indirect result of the investment.
We will also act to neutralize any impact of the investment
on the Company's cost of capital through mechanisms, described below,
that establish caps on the costs of debt and equity in future rate
proceedings unless the Company demonstrates that the caps should not
apply. In essence, we adopt a rebuttable presumption that the costs
of debt and equity will not be higher than the caps. For existing
variable-rate debt (either long-term or short-term debt) on MPS's
books, we will use the current margin to the stated index as the
maximum margin allowable regardless of the Company's future
circumstances. The reason for this is that it is common practice in
negotiations regarding the breach of loan covenants for lenders to
increase the margins they charge the borrower and also to impose
additional fees. Currently, MPS's short-term borrowing rate (per its
revolving loan agreement) has a margin of 1.375% above the applicable
LIBOR Index, (4) with a provision that will reduce this margin to 1.000%
(2) MPS will have both the burden of production and burden of
persuasion in such proceedings.
(3) In the event that the portion of a requested rate increase
attributable to the EA investment cannot be readily determined, we
will approximate an amount based on any available information.
(4) MPS's overall cost rate could go up whenever the underlying
LIBOR index increases. We would confine our adjustments to the
margin over the index, unless an event at EA caused the Lenders to
change MPS's underlying index to something higher than the initial
(or current) index such as the Prime Rate.
Order -6- Docket No. 98-138
when MPS meets certain financial ratio tests. In future proceedings,
we will maintain this margin of 1.00% above the LIBOR index for the
Company's short-term debt for ratemaking purposes as caps on the cost
of debt unless the Company can demonstrate that an increase in the
margin is not related to its investment in EA.
In addition, MPS has two long-term variable rate debt issuances
outstanding, one through the MPUFB and the other through the Finance Authority
of Maine (FAME). These issuances have credit enhancements provided by third
parties in addition to carrying variable rates. In the case of the Maine Public
Utility Financing Bank (MPUFB) issuance, the enhancement is a letter of credit
that has a commitment fee currently equal to 1.375% of the available amount of
the letter. As with MPS's revolving short-term credit line, there is a
provision in place for this fee to be reduced to 1.00% of the available letter
amount when MPS meets a certain financial ratio test. The possibility of new
fees and higher rates also exists with the company's fixed-rate long-term debt.
We will similarly cap MPS's fixed-rate long-term debt instruments at their
current embedded cost rates subject to a demonstration that a higher rate is
unrelated to EA.
It is conceivable that MPS could require future debt issuances for
utility purposes but be in a weakened financial condition due to some event at
EA. To prevent ratepayers from being subject to this risk, MPS's future debt
cost will be capped at the then current rate on investment grade utility bonds
(defined as having a rating not lower than BBB- from S&P, Fitch or Duff &
Phelps, or Baa3 from Moody's).
The question of segregating any cost impact of the EA investment on
MPS's cost of equity is more complex. We adopt a methodology to cap the
Company's cost of equity using a variation of a risk premium approach to
insulate MPS's ratepayers from changes in cost of equity due to investments in
EA. Rather than using Treasury or other debt instruments as the benchmark to
which an equity risk premium would be added, we will use an industry-specific
risk premium for the foreseeable future. Specifically, we will calculate both
the current cost of equity for a peer group of electric utilities comparable to
MPS as well as the current cost of equity for an index of water utilities to
determine an appropriate premium (if any) for the electric industry today versus
the water utility industry. As part of MPS's upcoming proceeding to establish
transmission and distribution rates, we will determine an appropriate "electric
industry" cost of equity margin for MPS. This margin would then be added to the
calculated result for the same index of water utilities at a point in the future
when the question may arise in order to determine a maximum possible cost of
equity for MPS. The water utility industry is our benchmark in this methodology
because it is
Order -7- Docket No. 98-138
not currently undergoing substantial structural change and remains
largely a monopoly service. It is reasonable to compare the future
T&D utility industry to the water utility industry today. (5)
Therefore, the water industry appears to be a good proxy for the T&D
utility industry for the foreseeable future. If future structural
changes in the water industry invalidate this comparison, we will
revisit this position. For the time being, however, this methodology
would capture changes in the capital markets that would have an
impact on "pure utilities." (6)
Additionally, our reorganization approval contains the
following conditions:
- that the Commission may after providing MPS notice and
an opportunity for a hearing, order that no further
investment by MPS, in EA, be made upon a finding that such
action is necessary to protect the public interest. (7)
- that the Commission may, after providing MPS notice
and an opportunity for a hearing, order divestiture by
MPS of EA upon a finding that such action is necessary
to protect the public interest.
- that the Commission have reasonable access to all
books, records, documents and other information relating
to EA.
To conclude, we emphasize to MPS that despite its current
or future financial condition, we intend to fulfill our policy of
insulating ratepayers from the consequences of this investment.
Therefore, if MPS decides to go ahead with the investment, it is
doing so with the clear knowledge that rate relief will not be
afforded if the need is a consequence of the investment.
(5) This view of the future T&D industry is shared by Standard &
Poor's, Moody's and Fitch Investor's Service. See S&P's: "Global
Sector Review", October, 1997; Moody's: "Special Comment: Future
Electric Distributors; More Stable than Generators, But not Risk
Free", October 1997; Fitch's: "Utility Holding Companies Redeploy
Capital", November 1997.
(6) In the future, a sufficient number of "pure" T&D electric
utilities emerge, we may adopt methodologies that use those utilities
directly, rather than our present choice of the water companies plus
some margin.
(7) MPS indicated that its investment of $2 million in EA will be
made in increments.
Order -8- Docket No. 98-138
Under the conditions and requirements discussed above, we
approve MPS's petition for reorganization approval to create EA and
invest (through capital contributions, loans or loan guarantees) up
to $2 million. As requested by MPS, we also exempt the Company,
pursuant to 35-A M.R.S.A. s. 708(2)(A), from any further
reorganization approvals that may otherwise be triggered by each
individual capital contribution or loan by MPS to EA up to $2 million.
C. Separation Requirements and Standards of Conduct
The MPS request for approval to form EA implicates the
separation requirements and standards of conduct provisions of the
Electric Restructuring Act. (8) In enacting this legislation, the
Legislature prohibited utilities from engaging in the retail
marketing of electricity, but permitted such marketing to occur
through an affiliated corporation. To minimize potential market
abuses and anti-competitive activities that may occur through such an
affiliation, the Legislature required the Commission to establish
separation requirements and standards of conduct governing the
relationship between utilities and their marketing affiliates. On
July 1, 1998, the Commission issued a Notice of Rulemaking, proposing
such rules (Docket No. 98-457). Because the proposed rule reflects
the Commission's most recent views on appropriate separation
requirements, the Examiner, during the hearing on this matter, stated
that it may be reasonable to apply these rules to MPS and EA pending
the final adoption of the rules. Accordingly, the Examiner asked MPS
to respond to the application of the proposed rules, and request and
justify any exception from those rules.
On July 15, 1998, MPS responded to the Examiner's request.
MPS indicated that, except for the sharing of employees prohibition,
MPS and EA would comply with the provisions of the proposed rule.
Pursuant to the terms of the proposed rule, MPS requested certain
exemptions from the employee sharing prohibition.
The employee sharing prohibition is contained in
subsection (L) of section 3 of the proposed rule. The subsection
prohibits the sharing of employees among utilities and their
marketing affiliates, and requires employees of the affiliate to be
located in a separate building. The prohibition applies even if the
employee is employed by one entity and only performs work for the
other entity. The provision does allow for an exemption upon a
specific finding that:
- sharing employees or facilities would be in the best interest
of the public;
(8) P.L. 1997, ch. 316, "An Act to Restructure the State's Electric
Industry," (codified as Chapter 32, Title 35-A).
Order -9- Docket No. 98-138
- sharing employees or facilities would have no
anti-competitive effect; and,
- the cost of any shared employees or facilities can be fully
and accurately allocated between the utility and the
marketing affiliate.
In its July 15 filing, MPS (on behalf of itself and EA)
requested an exemption from subsection (L) for four specific
activities:
1. To allow MPS to perform the management service
contract;
2. To permit EA's employees, through a date no later than
February 2000, to occupy a portion of the MPS office;
3. To permit MPS employees to perform accounting and
human resource services; and,
4. To permit certain employees of EA to engage in
wholesale sales of electricity to which MPS has an
entitlement but is surplus to its needs; the
arrangement would expire on February 29, 2000.
Because the proposed standards of conduct rule represent
the latest articulation of our views in this area, we will require
MPS, as a condition of approval, to comply with the provisions of the
proposed rule pending the final adoption unless we grant specific
exemptions. We address each of MPS's requests for exemption below.
We will also address the proposal to allow EA to promote its
affiliation with MPS.
Management Services
MPS requests an exemption from subsection (L) to allow it
to perform overall management and corporate oversight, noting that
the day-to-day management will be left to EA's principals. Such
management and oversight would include reviewing EA's request for
funding or review of any proposed major contract between EA and a
potential business ally. In support of the exemption, MPS states
that it would be in the public interest because allowing MPS to
provide these management services will reduce the risk of EA's
business failure which is in the best interest of MPS's ratepayers.
MPS addresses the potential anti-competitive effect by proposing
conditions intended to prevent EA from obtaining a market advantage
through access to information obtained by MPS by virtue of its status
as a regulated utility. Specifically, MPS proposes:
Order -10- Docket No. 98-138
- immediate contact between EA and MPS personnel during the
performance of the management service contract will be
conducted by the President and/or one member of MPS's senior
management, selected by the President, who will retain that
function for the term of the management services contract.
These individuals will maintain a log of all immediate
contacts between themselves and EA personnel, and every six
months will provide a copy of this log to the Commission.
- neither of these individuals will disclose to any EA
employee any information obtained by MPS solely as a result
of its status as a provider of core utility services unless
that information is also disclosed to non-affiliated
competitive electricity providers. (9)
To address cost allocation issues, all MPS employees who
provide services to EA under the management service contract will
keep a record of their time, which will provide a basis for monthly
invoices sent to EA under the contract. MPS states that because
these services are neither tariffed nor readily available in the
market, it will charge EA on a fully distributed cost basis.
Chapter 820, section 4(A) governs the cost allocation of
shared employees and requires that such allocation be done using a
tariffed rate if available, the market rate if the tariffed rate is
unavailable, or the fully distributed cost (FDC) methodology if
neither a tariffed rate nor the market rate is available. MPS states
that there is not a market value that can be determined for the MPS
employees that will be shared with EA, (10) and therefore it must
allocate the cost of shared employees between MPS and EA using the
FDC methodology. It is our view that for shared employees the FDC
allocation should result in a value close to the market value of such
employees unless they are currently being significantly under- or
(9) We interpret MPS's description of the applicable information
broadly to mean all information that is obtained as a result or as a
consequence of MPS performing its obligations as a regulated
utility. Unless otherwise indicated, we interpret language requiring
disclosure to non-affiliated providers to mean the disclosure will
occur simultaneously or as soon as practicable after the information
is given to the affiliate. MPS uses this or similar language in
other proposed conditions. Unless otherwise indicated, we interpret
the language as stated in this footnote.
(10) As discussed below, MPS also proposes that accounting and
human resource employees provide service to EA.
Order -11- Docket No. 98-138
over-compensated. Therefore, we will accept the FDC methodology as a
proxy for the market value of shared employees.
We do, however, disagree with one aspect of the Company's
proposal to implement the FDC methodology. In Attachment A to the
Company's July 15, 1998 letter, MPS indicates that it would apply a
payroll overhead rate to the labor dollars to allocate the cost of
benefits provided to MPS employees that are shared with EA. (11) MPS
notes that this overhead amount would be based on MPS's total payroll
dollars. We do not know how this average overhead rate would compare
to the actual overhead associated with the specific employees that
will be shared between MPS and EA; however, we assume there could be
significant difference, depending on which individual employees are
shared with EA. Therefore, we will require MPS to allocate the
actual overhead costs for the individual employees shared between MPS
and EA.
With this modification, we find that the provision of
management services pursuant to the proposed conditions satisfies the
requirement under subsection (L). Therefore, we allow the sharing of
employees under the conditions and restrictions described above and
in the MPS July 15 filing. Our approval is premised on the nature of
the management oversight being similar to that of a board of
directors, rather than that of executive management. As part of our
conditions for approval, MPS is required to notify the Commission in
writing as to the information provided to EA and the means by which
the information was disclosed to non-affiliated providers.
Sharing of MPS Office
MPS requests that EA employees be allowed to conduct
business from its operation center, where the majority of MPS
employees are also housed. MPS states that the arrangement would be
transitional until March 1, 2000; at that time, the expectation is
that EA will be in a separate facility. MPS justifies the
arrangement by stating that it does not require the space for its own
operation and any rent will be an additional profit for MPS.
Additionally, EA will begin operations with very few employees and
expand over the first two years of operation; until EA is actually up
and running, it is difficult to know the actual space requirements.
(11) The Company also indicated that its bills to EA will include a
factor to allocate a share of MPS's computer- and building-related
expenses associated with providing management services to EA.
However, the Company has not indicated how it will develop this
factor. Therefore, we require the Company to file for approval of
this factor at the time it files its accounting and human resources
agreement for 35-A M.R.S.A. s. 707 approval, as discussed later in
this document.
Order -12- Docket No. 98-138
MPS states that the transitional arrangement is in the public
interest because it provides rental income to the parent and avoids
economically wasteful expenditures by the subsidiary. To avoid any
anti-competitive effects, MPS proposes the following restrictions:
- EA personnel shall not have access to any MPS computer
facilities or equipment;
- EA personnel shall be served by a separate outside
telephone line (EA calls will not go through the MPS
switchboard), thereby avoiding the appearance of joint
advertising or affiliate promotion by the parent;
- In order to prevent the preferential flow of market
information from MPS to EA, the traffic between EA and MPS
employees shall be subject to the following restrictions:
- EA employees shall not be allowed in any MPS work area
and except for their own work area, which is distinct
from the rest of the operations center, EA employees
shall be allowed only in non-work related areas (e.g.,
restrooms, corridors);
- Any MPS employee who enters the EA work area shall
log in and out and write the nature of his/her
business. The log shall be available for inspection
by the Commission at any time; and
- No MPS employee shall disclose to any EA employee
any information obtained by MPS solely as a result of
its role as a provider of core utility services unless
that information is reasonably available to all
competitors on an equal basis.
Regarding cost allocation, MPS states that because a market
rate for commercial space in the Presque Isle area can be determined,
MPS will charge EA a monthly rental fee based upon the local market
in accordance with Chapter 820, section 4(A).
We find that allowing the sharing of the MPS office for a
transitional period under the conditions proposed by MPS satisfies
the requirements under subsection (L). We, therefore, allow EA to be
housed in the MPS operations center until March 1, 2000 under the
conditions specified in the July 15 filing.
Accounting/Human Resource Services
MPS states that EA will not be large enough, at least
during the first several years, to support its own accounting and
Order -13- Docket No. 98-138
human resource personnel, and therefore requests an exemption to
allow EA to obtain these services from MPS for an indefinite period.
MPS proposes that EA employees continue, at least initially, to
participate in the employee benefits package and general insurance
coverage plan currently provided by MPS. (12) This continued
participation allows EA to benefit from the economies of scale
enjoyed by MPS's larger employee population. MPS notes that although
this provides an advantage to EA, it is not an advantage related to
MPS's status as a provider of regulated services. Similarly, MPS
states that it would not be cost effective for EA, at least
initially, to employ its own accounting staff and, because MPS would
have to duplicate much of the work done by a third-party accountant,
there is an economy of scale in allowing accounting services to be
provided by MPS personnel.
MPS states that an exemption in these areas is in the
public interest because the realization of economies of scale reduces
EA's costs, and allows EA's principals to focus on business
activities that should enhance EA's chances of success. Similarly,
EA can realize economies by using the parent's accounting services
which should avoid economic waste. To address any anti-competitive
effect from the arrangements discussed above, MPS proposes to limit
immediate contact between MPS and EA to a single employee of MPS's
human resources department and a single member of MPS's accounting
department. MPS states that like management services, human resource
and accounting services are not tariffed and not readily available in
local markets; therefore EA will be charged for these services on a
fully distributed cost basis. For the reasons discussed above, we
will accept use of the FDC methodology as a proxy for the market
value of the services of shared employees. (13)
We find that allowing MPS to provide human resources and
accounting services satisfies the requirements of subsection (L).
We, therefore, allow MPS to provide accounting and human resource
services pursuant to the conditions stated in the July 15 filing.
Sale of Excess Power
In its July 15 filing, MPS stated that until March 1, 2000
it will retain rights to the output of both its Tinker hydro facility
and its Wyman 4 entitlement; the entire Wyman 4 entitlement is excess
to MPS's needs, and the hydro production is excess at certain times
during the year. MPS indicated that the individual most experienced
(12) MPS is required to submit the actual contract to the
Commission for approval under 35-A M.R.S.A. s. 707.
(13) Consistent with our earlier discussion, we require MPS to
allocate overheads associated with the specific employees, rather
than using a Company-wide average.
Order -14- Docket No. 98-138
in making wholesale sales of excess power, Ed Howard, will be
transferred to EA immediately upon its creation. MPS proposes to
have Mr. Howard continue to perform this function through February
29, 2000 while he is employed at EA. MPS indicated that although
off-system wholesale sales have produced substantial revenues to the
benefit of MPS's customers in the past, such direct benefits of these
sales can no longer occur because, according to MPS, these off-system
sales are non-core activities under Chapter 820(2)(C). As such, MPS
claims that they must be performed by an unregulated affiliate and
should not be considered a service performed for, or on behalf of
MPS, but solely for EA's own account. Under this theory, the
arrangement would not involve shared employees as defined in the
proposed rule. MPS states that if it is incorrect and its proposal
does amount to a "sharing of employees" as defined in the proposed
rule, MPS asks for an exemption to allow for the arrangement.
In support of its request for an exemption, MPS states that
there is a public benefit in imputing the revenues from such sales to
MPS for financial reporting purposes even though they are below the
line for ratemaking purposes, because such revenues will improve the
Company's financial indicators. In addressing potential
anti-competitive effects, MPS acknowledges that EA might conceivably
have access to information that MPS has obtained by virtue as its
status as a utility. To address the possible anti-competitive
effects, MPS proposes the following restrictions:
- all information provided to EA by MPS will be related to
and used by EA solely for the purpose of marketing excess
Wyman 4 and hydro production through February 29, 2000;
- within 30 days of its formation, and every six months
thereafter, MPS will inform the Commission of all information
it has provided to EA pursuant to EA's performance of these
excess power sales;
- by March 31, 2000, EA shall provide written notice to all
NEPOOL participants that they have the right, at their own
cost, to obtain copies of all information previously provided
to EA by MPS that MPS obtained solely as a result of its
status as a provider of regulated service; and,
- EA will limit the disclosure of any information received
from MPS only to Mr. Howard and the EA employees directly
involved in the marketing of MPS's surplus power. These
employees shall not disclose this information to any other EA
employees.
Regarding cost allocation, MPS states that, if this
non-core activity is conducted only through EA, then under Chapter
Order -15- Docket No. 98-138
820 there is no need for cost allocation. However, if the
interpretation is incorrect, then under 820, section 4(E), EA
services will be billed to MPS at market price.
We disagree with MPS's underlying premise that the
off-system sales of excess power from the Tinker facility and its
Wyman entitlement is a non-core activity under Chapter 820 and
therefore must be conducted through a separate unregulated affiliate.
The sale of excess power from facilities that MPS owns to satisfy its
obligations as a regulated utility is clearly not the type of
activity contemplated by Chapter 820 as non-core. Although the
wholesale sale is off-system and thus outside the Company's service
territory, it is so integrally related to its core activity that it
cannot reasonably be separated for such purposes. Utilities are
under an obligation to provide electricity to retail customers
through use of the lowest cost combination of resources. Satisfying
this obligation often involves purchasing and selling energy from
outside the utilities' service territory, in conjunction with
providing energy from utility-owned units. Viewed from this light,
off-system sales of energy from utility-owned units are simply a
component of the utility's core activity of providing least cost
energy to its customers. (14) Additionally, MPS's ratepayers have
traditionally borne the risk of cost recovery from the Company's
generating facilities and contracts and will continue to do so
through future stranded cost recovery. Therefore, the benefit of any
sale of excess power must accrue to the ratepayers by accounting for
these revenues above the line. We note that until retail access
occurs and utilities are out of the generation services business,
gray areas will exist regarding the nature of wholesale sales of
electricity as core or non-core. To the extent a situation falls
within the gray area, MPS should seek clarification from us. (15)
Having found that the described activity is not a non-core
activity, we address whether the arrangement should be allowed.
Consistent with our decision in the Central Maine Power Company's
request to form a marketing affiliate, Order, Docket No. 97-930 (July
(14) This situation is distinguished from that in which EA buys
power from the wholesale market and resells it outside MPS's service
territory. Such an action would be a non-core activity.
(15) During the hearing in this matter, MPS announced that it
recently entered a wholesale contract to provide power to Houlton
Water Company and that it anticipates transferring the contract to
EA. Because of the historical relationship of Houlton as an all
requirements wholesale customer of MPS and because retail ratepayers
have, at least to some degree, been at risk for lost wholesale
revenue, such a transfer may not be appropriate. We will address
this issue when MPS files for approval to transfer the contract.
Order -16- Docket No. 98-138
6, 1998), we will allow MPS to contract with its marketing affiliate
to provide for the resale of power services. (16) To address the
potential for anti-competitive impacts of the arrangement, we adopt
MPS's proposed restrictions, as supplemented below. MPS proposes
that EA provide notice to all NEPOOL participants that they have the
right, at their own cost, to obtain copies of all information
previously provided to EA. Because MPS is not in the NEPOOL control
area, we require MPS to also offer to provide the information to all
other competitive providers of electricity that it can identify that
may do business in its area. MPS must make a reasonable effort to
identify all potential providers, and offer the information to all
providers licensed by the Commission. MPS will be under a continuing
obligation to make the information available to new providers as they
become licensed by the Commission. The obligation will continue
until the Commission finds that the information has become stale and
thus useless. Regarding the costs that a provider must pay to obtain
the information, MPS or EA shall charge providers only the same costs
that EA is charged for the same information. If providers are
charged, the compensation should be paid to MPS and accounted for
above the line.
Finally, because EA will be providing this service to MPS,
MPS will be required to file for approval of the transaction pursuant
to 35-A M.R.S.A. s. 707; the filing should include a description of
how the market price of the services is determined. In the event the
costs to MPS of purchasing the services from EA is greater than the
costs that would have occurred if Mr. Howard services were retained
in-house and MPS sold the excess power itself, the difference in cost
shall be borne by shareholders. MPS is under a continuing obligation
to demonstrate that such cost differences are not paid by ratepayers.
Use of the MPS Name
In its original filing in this case, MPS proposed that EA
be allowed to promote its affiliation with MPS. Such an action by EA
would be prohibited under subsection (J) of the proposed rule. MPS
did not address this matter in its July 15 filing, but during the
hearing stated that subsection (J) would not apply because it only
restricts the utility in engaging in joint advertising or marketing,
not the affiliate.
We disagree with MPS. Subsection (J) of the proposed rule
defines joint advertising or marketing programs to include the use of
the same or substantially similar name that would require payment for
goodwill under Chapter 820. MPS recognizes that the ability of EA to
advertise its affiliation requires a payment for goodwill under
(16) In the event that retail access in Northern Maine is delayed,
the Commission and the Company will need to generally re-evaluate
MPS's arrangement with EA.
Order -17- Docket No. 98-138
Chapter 820, in that MPS proposed such a payment. Because the use of
the MPS name as contemplated in its filing is prohibited by the
proposed rule, we will not allow EA to do so pending the final
adoption of the rule. Because of this finding, we need not address
whether MPS's proposal for payment for goodwill is consistent with
Chapter 820's policies.
D. Section 707 Affiliated Interest Transactions
As stated above, MPS seeks section 707 approval for four
affiliated interest transactions. Consistent with our prior
discussion and subject to the applicable conditions and restrictions
stated above, we approve the following transactions:
- MPS making or guaranteeing loans to EA;
- LLC operating agreement;
- Management services agreement.
Also consistent with our prior discussion, we deny approval of the
intangible asset agreement.
Accordingly, we
O R D E R
1. That the reorganization to create a wholly-owned energy
marketing affiliated is hereby approved pursuant to 35-A M.R.S.A.
s. 708, subject to the conditions and restrictions described in the
body of this Order.
2. That a capital contribution not to exceed $2 million is
hereby approved pursuant to 35-A M.R.S.A. s. 708, subject to the
conditions and restrictions described in the body of this Order.
3. That a waiver of further reorganization approvals is hereby
granted pursuant to 35-A M.R.S.A. s. 708(2)(A) as described in the
body of this Order.
4. That loans or loan guarantees not to exceed $2 million
(inclusive of capital contributions) are hereby approved pursuant to
35-A M.R.S.A. s. 707 subject to the conditions and restrictions
described in the body of this Order.
5. That the LLC operating agreement is hereby approved
pursuant to 35-A M.R.S.A. s. 707 subject to the conditions and
restrictions described in the body of this Order.
Order -18- Docket No. 98-138
6. That the management service agreement is hereby approved
pursuant to 35-A M.R.S.A. s. 707 subject to the conditions and
restrictions described in the body of this Order.
7. That the petition for approval of the agreement with
respect to certain intangible assets is hereby denied.
Dated at Augusta, Maine this 2nd day of September, 1998.
BY ORDER OF THE COMMISSION
/s/ Dennis L. Keschl
Dennis L. Keschl
Administrative Director
COMMISSIONERS VOTING FOR: Welch
Nugent
Order -19- Docket No. 98-138
NOTICE OF RIGHTS TO REVIEW OR APPEAL
5 M.R.S.A. s. 9061 requires the Public Utilities Commission to
give each party to an adjudicatory proceeding written notice of the
party's rights to review or appeal of its decision made at the
conclusion of the adjudicatory proceeding. The methods of review or
appeal of PUC decisions at the conclusion of an adjudicatory
proceeding are as follows:
1. Reconsideration of the Commission's Order may be requested
under Section 1004 of the Commission's Rules of Practice and
Procedure (65-407 C.M.R.110) within 20 days of the date of the
Order by filing a petition with the Commission stating the
grounds upon which reconsideration is sought.
2. Appeal of a final decision of the Commission may be taken
to the Law Court by filing, within 30 days of the date of the
Order, a Notice of Appeal with the Administrative Director of
the Commission, pursuant to 35-A M.R.S.A. s. 1320 (1)-(4) and the
Maine Rules of Civil Procedure, Rule 73 et seq.
3. Additional court review of constitutional issues or issues
involving the justness or reasonableness of rates may be had by
the filing of an appeal with the Law Court, pursuant to 35-A
M.R.S.A. s. 1320 (5).
Note: The attachment of this Notice to a document does not indicate
the Commission's view that the particular document may be
subject to review or appeal. Similarly, the failure of the
Commission to attach a copy of this Notice to a document does
not indicate the Commission's view that the document is not
subject to review or appeal.
Exhibit 99(s)
STATE OF MAINE Docket No. 98-865
PUBLIC UTILITIES COMMISSION
December 15, 1998
MAINE PUBLIC SERVICE COMPANY ORDER GRANTING MOTION TO
Annual Increase Under Rate EXTEND RSP DEADLINE FOR
Stabilization Plan ANNUAL INCREASE
WELCH, Chairman; NUGENT and DIAMOND, Commissioners
In this Order we grant Maine Public Service Company"s Motion
to permit its annual price change to take effect on April 1, 1999
rather than February 1, 1999. We also, at this time, modify our
Order in Docket No. 95-052 and extend the term of the Company's
Rate Stability Plan by one additional month.
On November 13, 1998, Maine Public Service Company (MPS or
the Company) submitted its annual price change filing pursuant to
the Company's Rate Stability Plan ("RSP") approved by the
Commission in Maine Public Service Company, Proposed Increase in
Rates, Docket No. 95-052, Order Approving Stipulation (Rate
Case/Rate Plan)(Me. PUC, November 30, 1995). As part of its
November 13th rate plan submission, the Company filed a motion to
amend the Commission's original order in Docket No. 95-052 to
permit this year's Rate Stability Plan increase to become
effective on April 1, 1999 rather than on February 1, 1999. The
extension will allow the Commission to decide the Company's
proposed generation asset sale case, Docket No. 98-584, prior to
the implementation of this year's annual Rate Stabilization Plan
rate change. According to the Company, a favorable decision in
the asset sale case would allow the Company to delay at least
part of this year's authorized rate increase.
The Company's extension request is made subject to the
condition that the Company be permitted to collect in rates the
full amount to which it would have been entitled had the rate
increase been effective February 1, 1999 if the proposed sale of
its generation assets is not approved in Docket No. 98-584. The
Company also requests in its motion that the term of the Rate
Stability Plan be extended by one additional month, or until
February 29, 2000, to coincide with the scheduled start of retail
competition for generation services in Maine. The Company's
motion is unopposed by the Public Advocate, the only other party
in this matter.
Order Granting . . . -2- Docket No. 98-865
We find that the Company's requests are consistent with the
interests of the Company's ratepayers and also provide certain
administrative benefits. The Company's motion is, therefore,
granted. Our approval in no way constitutes an approval of the
rate increase claimed due by the Company or a determination of
the amount of the increase to go in effect on April 1, 1999.
These matters will be addressed in our final order in this
docket, which will now be issued in March, 1999.
Accordingly, we
O R D E R
1. That the effective date of the annual rate change under the
Company's Rate Stabilization Plan, approved by the Commission in
Docket No. 95-052, is extended from February 1, 1999 to April 1,
1999.
2. The expiration date of the Company's Rate Stabilization Plan
is extended by one month from January 30, 2000 to February 29,
2000.
Dated at Augusta, Maine this 15th day of December, 1998.
BY ORDER OF THE COMMISSION
/s/ Dennis L. Keschl
Dennis L. Keschl
Administrative Director
COMMISSIONERS VOTING FOR: Nugent
Diamond
COMMISSIONER ABSENT: Welch
Order Granting . . . -3- Docket No. 98-865
NOTICE OF RIGHTS TO REVIEW OR APPEAL
5 M.R.S.A. s. 9061 requires the Public Utilities Commission
to give each party to an adjudicatory proceeding written notice
of the party's rights to review or appeal of its decision made at
the conclusion of the adjudicatory proceeding. The methods of
review or appeal of PUC decisions at the conclusion of an
adjudicatory proceeding are as follows:
1. Reconsideration of the Commission's Order may be
requested under Section 1004 of the Commission's Rules of
Practice and Procedure (65-407 C.M.R.110) within 20 days of
the date of the Order by filing a petition with the Commis-
sion stating the grounds upon which reconsideration is
sought.
2. Appeal of a final decision of the Commission may be
taken to the Law Court by filing, within 30 days of the date
of the Order, a Notice of Appeal with the Administrative
Director of the Commission, pursuant to 35-A M.R.S.A. s. 1320
(1)-(4) and the Maine Rules of Civil Procedure, Rule 73 et
seq.
3. Additional court review of constitutional issues or
issues involving the justness or reasonableness of rates may
be had by the filing of an appeal with the Law Court, pursu-
ant to 35-A M.R.S.A. s. 1320 (5).
Note:The attachment of this Notice to a document does not
indicate the Commission's view that the particular document
may be subject to review or appeal. Similarly, the failure
of the Commission to attach a copy of this Notice to a
document does not indicate the Commission's view that the
document is not subject to review or appeal.
Exhibit 99(t)
Maine Public Utilities Commission
Study of Northern Maine Connections
to the New England Grid
Docket No. 97-586
Competition and Market Power in
the Northern Maine Electricity Market
Prepared for the
Maine Public Utilities Commission
Prepared by
Tim Woolf and Bruce Biewald,
Synapse Energy Economics, and
Duncan Glover,
Exponent Failure Analysis
November 24, 1998
Synapse Energy Economics, 22 Crescent Street, Cambridge MA, 02138, (617)
661-3248
Table Of Contents
1. Introduction and Summary 1
2. Competition in Northern Maine Under Current Conditions 8
2.1 Generation Capacity in Northern Maine -- Prior to the MPS
Divestiture 8
2.2 Results to Date of the MPS Generation Asset Divestiture 9
2.3 Transmission Capabilities in Northern Maine 10
2.4 Quantitative Indicators of Market Concentration in Northern Maine13
2.5 Limitations to the Herfindahl-Hirschman Index 16
2.6 The Importance of Accessing a Competitive Wholesale Electricity
Market 17
2.7 Options Available to Reduce Market Power in Northern Maine 18
3. Increase the Amount of Competition Within Northern Maine 19
4. Increase the Amount of Competitive Generation Available From
New Brunswick 22
5. Increase the Amount of Competitive Generation Available From Quebec 25
5.1 Access Hydro-Quebec Through New Brunswick Power 25
5.2 Build a New Transmission Line From Hydro Quebec to Northern Maine27
6. Increase the Amount of Competitive Generation Available From
New England 30
6.1 Access New England Through New Brunswick Power 30
6.2 Improve the South-to-North Flow on the MEPCO Transmission Line 31
6.3 Build a New Transmission Line from NEPOOL to Northern Maine 33
6.4 Encourage the Northern Maine Distribution Companies to Participate
in the ISO-NE Market 37
7. Conclusions and Recommendations 40
7.1 Synthesis of Our Analysis 40
7.2 Recommendations 43
7.3 The Costs and Benefits of Addressing Market Power in Northern
Maine 44
8. References 46
Appendix A. Map of Northern Maine and Regional Interconnections A-1
Appendix B. Herfindahl-Hirschman Index Calculations B-1
Appendix C. Transmission Cost Estimates C-1
Acknowledgements
The authors would like to thank the following people who provided invaluable
information during the course of our research, as well as useful insights and
comments on drafts of this report:
Mitch Tannenbaum, Maine Public Utilities Commission
Denis Bergeron, Maine Public Utilities Commission
Faith Huntington, Maine Public Utilities Commission
Marjorie Force, Maine Public Utilities Commission
Francis Ackerman, Maine Office of the Attorney General
Steve Johnson, Maine Public Service Company
Bill St. Cyr, Maine Public Service Company
Frederick Bustard, Maine Public Service Company
Steve Garwood, Central Maine Power Company
Jeff Jones, Bangor Hydro Electric
Darrell Bishop, New Brunswick Power
Arden Trenholm, New Brunswick Power
Catherine Bert, Hydro Quebec
John Miller, TransEnergy US
Gordon Weil, Weil and Howe Inc.
David Thorn, Weil and Howe Inc.
Jim Sinclair, ISO-New England
The findings, conclusions, recommendations and errors in this report are the
sole responsibility of the authors.
Disclaimer
The analyses, conclusions and recommendations in this report are those of the
authors, and not of the Maine Public Utilities Commission or Commission Staff.
1. Introduction and Summary
Background
The Maine Legislature recently signed into law a restructuring statute designed
to promote effective retail competition in the state's electricity generation
market. 1 The Legislature has also directed the Department of the Attorney
General (Department) and the Public Utilities Commission (Commission) to conduct
jointly a study of market power issues that may arise as a consequence of the
restructuring law. 2 The Commission and the Department released an interim
market power report in February 1998.
In addition, the Legislature directed the Commission to investigate how best to
ensure that customers in portions of Maine that are isolated from the rest of
New England can take advantage of retail competition. 3 The utilities in
northern Maine are not connected to other Maine utilities, and are not members
of the New England Power Pool (NEPOOL), and therefore face greater obstacles to
developing a sufficiently competitive electricity generation market. The
Commission issued a notice of inquiry (NOI) on this topic in January 1998
(Docket 97-586).
The purpose of this report is to inform the Legislature about the potential for
establishing an effectively competitive electricity generation market in
northern Maine. The results of this report will also be used as input to the
market power report prepared by the Commission and the Department and submitted
to the Legislature under separate cover.
The "market power" that we address in this report refers to the ability of a
firm or group of competing firms to profitably raise prices above competitive
levels for a sustained period of time. If one or more firms in the northern
Maine electricity market possess too much market power, then electricity
customers may not be able to enjoy many of the benefits of retail competition.
There are a number of factors that indicate that market power could be a
significant problem in northern Maine, including:
- There is a small number of power plants located within northern Maine,
and only three companies own them, or have entitlements to them.
- The divestiture of the Maine Public Service Company (MPS) generation
assets to WPS Power Development, as proposed, will not increase the
number of generation owners in northern Maine. However, one or more
additional companies might access the market by acquiring power from the
Wheelabrator-Sherman facility.
1. P.L. 1997 ch.316, much of which is codified at 35-A M.M.S.A. sections 3201-
3217.
2. P.L. 1997 ch.447 Part B.
3. 35-A M.M.S.A. section 3206.
Competition and Market Power in the Northern Maine Electricity Market Page 1
- The region is not interconnected with any neighboring utilities except
for New Brunswick Power Company (NBP). This might limit the number of
competitive generation companies that can serve northern Maine.
- NBP has the ability to exploit its dominant role with regard to
transmission in the region. NBP is not currently regulated and has the
flexibility to unilaterally increase or decrease its transmission rates.
- NBP's current transmission tariffs require that generation companies
seeking to wheel power through NBP to northern Maine must pay higher
transmission prices than those paid by NBP.
- NBP's transmission pricing flexibility has a chilling effect on
transmission options in the region. Increasing the transmission price
would further limit the ability of new generation companies to reach
northern Maine. Reducing the price would reduce the economic benefits
to a third party of building a new transmission line to northern Maine.
- Hydro-Quebec (HQ) is currently not willing to sell power into the
northern Maine market, because NBP's transmission tariff is not
comparable with its own. However, Hydro-Quebec is able to sell power at
its border with NBP; a generation company could then sell this power into
northern Maine by transmitting it across NBP's system.
- Generation companies located in New England will have to overcome
transmission stability constraints that limit the amount of firm power
that can be transmitted from the south to the north on the Maine Electric
Power Company (MEPCO) transmission line.
- Generation companies in New England might be reluctant to sell power into
the northern Maine market, due to the high NBP wheel-through tariff and
the MEPCO transmission constraints.
- Electricity customers in northern Maine currently do not have access to
a competitive wholesale electricity market, denying them of the benefits
of an Independent System Operator (ISO) and a competitive spot market.
However, the conditions in the region are changing in some ways that might help
to mitigate or eliminate some market power concerns. For example:
- A working group of the northern Maine transmission and distribution (T&D)
utilities has been formed with the purpose of studying the various
options for establishing a competitive electricity market in northern
Maine, including the option of creating a Bulk Power System Administrator
(BPSA).
- NBP has offered to take a number of steps to promote greater competition
in the region, including (a) providing a Tie Line Interruption Service
that can provide back-up power to mitigate the south-to-north constraint
on the MEPCO line, (b) providing fixed terms and conditions for its
transmission tariff, including a price cap, (c) unbundling its operations
and providing services under a code of conduct, (d) working with the
government of New Brunswick to establish a
Competition and Market Power in the Northern Maine Electricity Market Page 2
process to regulate New Brunswick Power's transmission services, (e)
working with the Commission to develop regulations and contractual
arrangements that would lead to market conditions satisfactory to the
Commission, and (f) supporting the efforts of the Northern Maine Working
Group in developing a BPSA for the region.
- TransEnergie US, a subsidiary of Hydro-Quebec, is investigating the
option of constructing a transmission line that would connect HQ with
MPS.
- Bangor Hydro Electric Company (BHE) has developed plans and obtained
permits for a new transmission line connecting it to NBP, creating an
alternative to the MEPCO line for delivering power from New England to
NBP.
- The new transmission line between BHE and NBP might help mitigate the
south-to-north constraint on the MEPCO line. A transmission tap into the
MEPCO line by the Bowater paper company might also help mitigate the
south-to-north constraint on the MEPCO line.
- Private developers are currently planning two new gas-fired power plants
in New Brunswick, creating opportunities for sales of power to US
markets.
- The New Brunswick government is currently undertaking a legislative
review of restructuring and regulation of the electric power industry in
New Brunswick.
Framework of Our Analysis
Our analysis begins with an overview of the generation and transmission
conditions in northern Maine. We then assess the amount of market concentration
in the northern Maine region, with the use of the Herfindahl-Hirschman Index
(HHI). The HHIs indicate that there is currently a high degree of market
concentration in northern Maine, and that adverse market power effects are
likely. Most of the market concentration is due to NBP's influence over
transmission in the region.
We then identify a set of strategies that could be used to mitigate the market
power concerns in northern Maine. We note that accessing a competitive
wholesale electricity market -- including a competitive spot market, an ISO, and
open-access, non-discriminatory transmission services -- is necessary to
eliminate market power concerns in northern Maine.
Table 1.1 describes the framework we used to assess strategies to mitigate
market power. We evaluate the following four general strategies that could
provide opportunities for reducing the market power concerns in northern Maine:
1. Increase the amount of competition within northern Maine.
2. Increase the amount of competitive generation available from New Brunswick.
3. Increase the amount of competitive generation available from Quebec.
4. Increase the amount of competitive generation available from New England.
Competition and Market Power in the Northern Maine Electricity Market Page 3
Table 1.1 Framework For Assessing Options to Mitigate Market Power in Northern
Maine
Source of Northern New Hydro New
Competitive Maine Brunswick Quebec England
Generation
Transmission New Line New Line
Access to Reach None NBP NBP from HQ NBP from MEPCO
Northern Maine needed Line Line to MPS Line to MPS
Potential for
Competitive Very
Wholesale Market Limited Unlikely Unlikely Unlikely Likely Likely
Likely Number Five Six Six
of Competitors Four or more or more or more Many Many
Herfindahl
Index for 1460- 1526-
Northern Maine 2397-2933 1727 1727 2157 1727 2157
Transmission
Cost to Reach 24 34 32-48 34 22-35
Northern Maine None $/kW-year $/kW-year $/kW-year $/kW-year $/kW-year
Actions Necessary 3, 6 6, 7
to Mitigate Market 1 2 and 3 3 and 4 4 and 5 and 8 and 8
Actions necessary to mitigate market power:
1. Increase the number of generators located within northern Maine.
2. Make the wholesale market in New Brunswick more competitive.
3. Convince NBP to provide open-access, non-discriminatory firm transmission
capacity.
4. Make the wholesale market in Quebec more competitive.
5. Build a new transmission line between Hydro-Quebec and MPS.
6. Resolve the south-to-north constraint on the MEPCO transmission line.
7. Build a new transmission line between MPS and MEPCO.
8. Encourage distribution companies in northern Maine to participate in the
ISO-NE market.
It should be noted that our analysis focuses on market power in generation
services in general. We do not look at the distinction between energy,
short-term capacity or long-term capacity. Furthermore, we do not address the
market power problems that can arise in the market for ancillary services.
Problems associated with ancillary services can be significant, especially given
that NBP and MPS are in the position of providing most, if not all, of the
ancillary services in the region. Finally, this study does not address how
market power problems might be exacerbated by the renewable portfolio standard
that is required by the Maine restructuring legislation.
Conclusions
Under current conditions the electricity market in northern Maine is likely to
be subject to market power problems. While some of the market power issues can
be mitigated by the strategies and options discussed in the study, the greatest
cause of market power concern
Competition and Market Power in the Northern Maine Electricity Market Page 4
- -- New Brunswick Power -- poses a significant challenge. NBP has the ability
to exploit its role as the only provider of transmission into northern Maine,
thereby limiting the amount of competitive generation suppliers that can reach
the area. Not only does it have control over all of the existing transmission
into northern Maine, it could also play an influential role in assisting or
hindering many of the solutions that we have considered in this study.
NBP's recent offers to promote greater competition in the region are an
important step in the right direction. However, there are additional steps that
NBP can make to assure regulators and generation companies that it is willing
to provide open access, non-discriminatory transmission services into northern
Maine. In particular:
- NBP should follow-through with its offer to contractually agree to fixed
terms and conditions of its transmission tariff, and should offer the
same terms and conditions to all generation companies purchasing
transmission services.
- NBP should follow-through with its offer to cap its transmission rates
until a regulatory body is established in New Brunswick with jurisdiction
over transmission tariffs.
- NBP should demonstrate that its transmission tariffs are comparable with
the Federal Energy Regulatory Commission's (FERC) pro-forma transmission
tariff.
- NBP should demonstrate that the terms and conditions of the transmission
services that it provides to others are comparable to the terms and
conditions of the transmission services that it takes for itself.
There are three broad conditions that will help ensure a fully competitive
retail electricity market in northern Maine. First, the region must be provided
with open access, non-discriminatory transmission services -- including
transmission services for imported power. Such import transmission services
could either be provided through NBP or through a new transmission line to the
rest of New England. Second, the northern Maine region must have access to a
fully competitive wholesale electricity market. We believe that the most likely
way to achieve this in the near term is by participating in the ISO-NE market.
Third, there must be a sufficient number of generation companies willing and
able to serve the northern Maine electricity market. If the first two
conditions are met, then it is likely that the third condition will be met as
well.
Recommendations
Given the potential for market power problems in northern Maine, we recommend
that the Commission address the issue from a number of angles. The two
overarching goals of the Commission should be: (1) to encourage the distribution
companies within northern Maine to obtain access to a fully competitive
wholesale electricity market, and (2) to promote open access, non-discriminatory
transmission services for power imported into the northern Maine system. To
help achieve these goals, we recommend the Commission pursue the following
specific actions:
Competition and Market Power in the Northern Maine Electricity Market Page 5
1. Conduct further research. There are a number of areas where further research
will shed light on some important issues raised in our study. For example, the
Commission should:
- Require the Northern Maine Working Group on Settlement to conduct a
thorough review of the costs and benefits of participating in the ISO-NE
market. The review should account for the benefits of reducing market
power concerns in northern Maine. The study should also include an
analysis of the advantages and disadvantages of participating in ISO-NE
versus developing and implementing the BPSA. 4
- Review TransEnergie's study of constructing a transmission line from
Hydro-Quebec to MPS. An initial draft of the study is due to be
completed soon.
- Investigate a new transmission line between New England and MPS. The
Commission should begin discussions with MPS, CMP, BHE, and MEPCO to
investigate the advantages and disadvantages of constructing such a line,
as well as who would act as project developer for the line.
2. Encourage NBP to provide truly non-discriminatory, open-access transmission
service. The four steps necessary for NBP to demonstrate that such transmission
service will be provided in the near term are: (a) NBP should contractually
agree to fixed terms and conditions of its transmission tariff for all
generation companies; (b) NBP should cap its transmission rates; (c) NBP should
demonstrate that its transmission tariffs are comparable with FERC's pro-forma
transmission tariff; and (d) NBP should demonstrate that the terms and
conditions of the transmission services that it provides to others are
comparable to the terms and conditions of the transmission services that it
takes for itself.
3. Oversee the development of the BPSA in northern Maine. The first order of
business should be to determine whether the services offered by the BPSA would
be better provided by participating in the ISO-NE market instead. If the BPSA
turns out to be the best or most practical approach, the Commission should
ensure that it is governed and operated in a way that (a) is independent of the
T&D utilities and NBP, (b) mitigates the market power concerns in the region,
and (c) includes market power monitoring and prevention measures similar to
those adopted by ISO-NE.
4. Encourage the distribution companies in northern Maine to participate in the
ISO-NE market, if further research indicates that participation is feasible and
the benefits are likely to exceeds the costs.
5. Work with NBP to follow-up on its offers to establish regulations and
contractual arrangements that would lead to market conditions satisfactory to
the Commission.
6. Participate in the New Brunswick government's legislative review process
regarding the restructuring and associated regulation of the electricity market
in New
______________________________________________
4. The northern Maine Working Group on Settlement has recently discussed the
option of participating in ISO-NE, and has begun corresponding with the ISO-NE
to inquire about the implications of participation. (MPS 10/21/1998).
Competition and Market Power in the Northern Maine Electricity Market Page 6
Brunswick. The Commission can play an important role in informing the New
Brunswick government about the conditions necessary to make the New Brunswick
market sufficiently competitive to support the northern Maine electricity
market.
Competition and Market Power in the Northern Maine Electricity Market Page 7
2. Competition in Northern Maine Under Current Conditions
2.1 Generation Capacity in Northern Maine -- Prior to the MPS Divestiture
In 1997 the peak demand in northern Maine was roughly 123 MW -- which is
approximately seven percent of the total demand in Maine, and less than one
percent of the demand in all of New England. Table 2.1 provides a summary of
the 1997 coincident peak demands of the northern Maine utilities.
The native load on the MPS system represents roughly 80 percent of total demand
in northern Maine. The other customers are served by two municipal utilities:
Houlton Water Company (HWC) and Van Buren Power and Light (VBPL), and one
electric cooperative: Eastern Maine Electric Coop (EMEC). Eastern Maine Electric
Coop serves a load of approximately 31 MW that is not connected to the MPS
system. This separate EMEC load is served through power delivered by NBP. It
is not included in Table 2.1. 5
Table 2.1 Coincident Peak Demand of Northern Maine Utilities in 1997.
Utility Source of Generation Peak Demand (MW) Percent of Total
MPS owns power plants 99.7 81%
Houlton Water Co. purchases 17.3 14%
Van Buren Light & Power purchases 3.0 2%
Eastern ME Coop purchases 2.5 2%
Total ---- 122.5 100%
Taken from MPS response to PUC Notice of Inquiry, Docket No. 97-586.
Table 2.2 provides a summary of the power plants located in northern Maine. The
Tinker hydro generating station is currently owned by the Maine and New
Brunswick Electric Power Limited (M&NB) -- a wholly owned subsidiary of MPS.
MPS is entitled to Tinker's energy and capacity, through a power contract with
M&NB. 6 MPS is also entitled to the 18.1 MW of capacity of the Wheelabrator
- -Sherman wood-fired cogeneration facility, through a qualifying facility
contract.
In addition, MPS owns two small hydro facilities and some small diesel units.
These units generate only a very small portion of MPS's electricity sales.
MPS also owns shares in the Wyman plant (21 MW) and the Maine Yankee plant (43
MW). Both of these plants are located outside of the northern Maine region.
The Maine Yankee plant has been permanently closed, and is therefore not
available to provide generation to northern Maine. The MPS shares in the Wyman
plant are not considered as
______________________________________________
5. While this study does not investigate the unique concerns of the separate
EMEC load, we assume that this load will be subject to at least the same market
power concerns that are experienced by the other utilities in northern Maine.
Therefore, when we refer to the northern Maine region in this study, we include
the separate load served by EMEC. Some of the solutions for mitigating market
power problems in northern Maine might not be successful in mitigating the
problems within the separate EMEC load.
6. MPS is required to use a portion of the Tinker output to serve the town of
Perth Andover.
Competition and Market Power in the Northern Maine Electricity Market Page 8
capacity available to the northern Maine market, because of limitations in
transmission capacity. (See Section 2.3.)
The other two sources of generation in northern Maine are wood-fired power
plants owned by the Aroostook Valley Electric Coop (AVEC) and Alternative Energy
Inc. (AEI). As indicated in Table 2.2, these two companies own roughly 25
percent of the capacity in northern Maine, while MPS owns or is entitled to the
remaining 50 percent.
Table 2.2 Generation Capacity Located in Northern Maine.
Owner Fuel Type Capacity (MW) Percentage of Total
MPS--Wheelabrator Wood 18.1 13%
MPS--ME & NB Elec. Power Hydro-Tinker 33.5 25%
MPS Hydro-Other 2.3 2%
MPS Diesels 12.3 9%
Aroostook Valley Elec. Coop. Wood 32.0 24%
Alternative Energy Inc. Wood 37.0 27%
Total Generation ---- 135.2 100%
Source: MPS response to data request 1-AGO-3, Docket No. 97-877, and Econosult
1998. The Tinker facility is located in Canada, just across the Maine border,
but its generation is available to customers in northern Maine.
In addition to the resources described above, MPS has signed short-term
contracts (1998-2000) with AEI and NB Power to purchase capacity and energy to
replace that which was lost due to the Maine Yankee shutdown. The contract with
AEI is for 37 MW and 260 GWh. The contract with NB Power is for 15 MW of
capacity and the necessary dispatchable energy to meet MPS's remaining
requirements (Bustard 1998).
2.2 Results to Date of the MPS Generation Asset Divestiture
In late 1997 MPS solicited bids for purchases of all of its generation assets,
in response to the Maine restructuring legislation's mandate to divest all
generation by March 2000. MPS received bids in January 1998, and selected the
winning bidder in August 1998. MPS's petition for authorization for the sale
of its generation assets is now being considered by the Commission in Docket No.
98-584.
MPS has announced that the winning bidder is WPS Power Development, Inc of Green
Bay, Wisconsin. WPS has offered to buy all of MPS's generation assets,
including all of MNBEP, which owns and operates the Tinker hydro facility. 7 The
proposed sale to WPS includes a Buy-Back Agreement, whereby MPS will have the
rights to all capacity, energy and ancillary services of the hydro and diesel
units, including the Tinker facility. The Buy-Back Agreement will be in effect
through February 2000.
MPS did not sell its entitlements in the Wheelabrator-Sherman facility.
Instead, MPS plans to sell the output from this facility on a short-term basis
at periodic auctions.
______________________________________
7. The legislation does not require MPS to divest the Tinker facility because
it is located outside the US.
Competition and Market Power in the Northern Maine Electricity Market Page 9
In sum, the MPS divestiture may result in a modest increase in the number of
generation companies located in northern Maine. AVEC and AEI will continue to
each own 24 and 27 percent of the generation in the region, respectively. WPS
will own approximately 36 percent, and whoever purchases the Wheelabrator
- -Sherman entitlements will hold the remaining 13 percent. If either AVEC, AEI
or WPS purchases the Wheelabrator-Sherman entitlements, then their shares of
capacity will increase accordingly.
2.3 Transmission Capabilities in Northern Maine
In theory, utilities in northern Maine have access to two broad external
electricity markets: Canada to the north and New England to the south. However,
in practice access to these markets are severely constrained by transmission
ties and institutional practices.
A map of northern Maine and regional transmission interconnections is provided
in Appendix A. Unlike other regions of Maine, the northern Maine utilities are
isolated from the New England transmission system. MPS's only external
transmission links are through New Brunswick Power. Hence all purchases and
sales with the New England market to the south must go through NBP, and be
transmitted through the MEPCO transmission line between NBP and BHE. 8
Similarly, all purchases and sales with the Canadian markets to the north must
be made through NBP.
Transmission Access Through New Brunswick Power
The transmission capacity between MPS and NBP is 200 MW. 9 The flows of power
between MPS and NBP are limited by transmission line conductors and tie line
transformer ratings (NBP 3/1998). For planning purposes, MPS assumes that the
inter-ties are able to carry 90 MW of power on a firm basis (Bustard, Louridas,
Brown 1998). However, one of the four transmission lines between the two
companies was only out of service between two and four days over the last two
years, indicating that MPS frequently has access to more than 90 MW of
transmission capacity with NBP (Econosult 1998). Either way, the transmission
capacity between NBP and MPS is quite large relative to the 123 MW peak demand
in northern Maine in 1997.
However, from an economic perspective the ability to purchase power through the
NBP interconnection is limited by NBP's transmission policies and rates. As of
January 1998, NBP has offered what it calls an open access transmission tariff.
The tariff only offers "wheel-out" and "wheel-through" point-to-point
transmission service. Generating companies are not offered transmission
services that terminate within NBP's service territory. The wheel-through rate
is roughly 34 $/kW-year and the wheel-out rate is approximately 24 $/kW-year.
10 NBP takes transmission services at its wheel-out rate, which provides it
with an economic advantage over generation companies outside of New Brunswick
seeking to transmit power into MPS's service territory. Within northern
________________________________
8. The Maine Electric Power Company is jointly owned by MPS, BHE and CMP, and
was established primarily to build and operate the MEPCO transmission line.
9. There are four transmission lines connecting northern Maine with NBP: two
69kv lines and two 138 kv lines (NBP 3/1998).
10. Here we assume an exchange rate of 0.65 US$/C$.
Competition and Market Power in the Northern Maine Electricity Market Page 10
Maine the cost of transmission is even lower, at an average price of roughly
$20/kW-year (Bustard, Louridas, Brown 1998).
NBP has stated that its transmission prices will not be increased over time by
more than the increase in the consumer price index (NBP 8/1998). However, NBP
is not subject to any regulatory body overseeing its transmission pricing and
practices, and it has not filed its transmission tariff at FERC. NBP notes that
it believes that over time an independent regulatory body will be established
to review and approve its transmission tariff and to set guidelines for a code
of conduct (NBP 8/1998). However, for the foreseeable future it appears as
though NBP has the flexibility to alter its transmission policies and prices
without regulatory oversight or legal recourse. Consequently, generation
companies in the region may be discouraged from depending upon NBP transmission
services to sell generation services into northern Maine. (This issue is
addressed in more detail in Section 5.)
NBP's transmission pricing flexibility could have a chilling effect on trans-
mission options in the region. Increasing the NBP wheel-through transmission
price would further limit the ability of new generation companies to reach
northern Maine. Reducing the NBP transmission price would reduce the economic
benefits to a third party of building a new transmission line to northern Maine.
In recent months New Brunswick Power has made a number of offers to mitigate
concerns about its transmission pricing practices. The Company points out that
the government of New Brunswick is currently conducting a legislative review
process regarding the restructuring of the New Brunswick electricity industry.
NBP expects that this process will result in some form of governmental
regulation over NBP's transmission services, as well as legislative changes to
facilitate development of independent power projects in New Brunswick. The
Company expects that a Legislative Energy Committee will announce its policy
direction for the future by Spring of 1999 (NBP 10/28/1998).
NBP has also offered to contractually agree to fixed terms and conditions for
its transmission tariff, including a cap on the transmission price. These terms
would apply to its transmission services into northern Maine, until a regulatory
body is established in New Brunswick with jurisdiction over NBP's transmission
tariff matters (NBP 10/28/1998).
NBP is also proceeding to arrange for the unbundling of its merchant activities
from its transmission services, and is developing a code of conduct that would
govern the operation of these two activities. NBP plans to achieve this
unbundling prior to the introduction of retail competition in Maine in March
2000 (NBP 10/28/1998).
NBP power notes that it will consider filing its transmission tariff with FERC,
after the tariff has been reviewed and approved by an appropriate New Brunswick
regulatory agency (NBP 10/28/1998).
Transmission Access From NEPOOL Over the MEPCO Line
Electricity customers in northern Maine face an important barrier arising from
constraints on the south-to-north flow on the MEPCO transmission line connecting
NBP to NEPOOL. The MEPCO line is subject to stability constraints that require
that the line
Competition and Market Power in the Northern Maine Electricity Market Page 11
maintains a constant flow of power from New Brunswick to NEPOOL. 11 This
north-to-south flow is required to ensure that in the event of the loss of the
largest source of power in the Maritime Control Area (usually the Point Lepreau
plant or the power from the Hydro Quebec transmission lines), there will not be
unacceptable voltage and power flow levels over the MEPCO line and into Maine
(NBP 3/1998). As explained by MPS:
Because the two adjacent control areas of NEPOOL and the Maritime Pool are
connected together by a single line (MEPCO), sudden events and disturbances
in one area have significant impacts on the other. The event of a sudden
loss of a large amount of generation in the Maritime control area will
cause intolerable grid voltage situations in Maine, unless, in the
pre-event period, power is flowing in the north-to-south direction
(Bustard, Louridas, Brown 1998).
In other words, two events must occur in order for there to be voltage and power
flow problems. First there must be a net south-to-north flow. Second, there
must be an unplanned loss of a large power source in the Maritime Control Area.
Since an unplanned loss of a power source cannot be prevented with certainty,
the operators of the MEPCO line maintain a net flow of power in the
north-to-south direction. NEPOOL rules require that the net flow south on the
MEPCO line exceed the flow north by 200 MW (ME AG 9/1998).
In recent years power has been less expensive in New Brunswick than in New
England, so there has almost always been a net north-to-south flow of power.
In fact, there is roughly 600 MW of firm capacity reserved on the MEPCO line for
the purpose of transmitting power from the north to the south. Nevertheless,
the south-to-north constraint remains in place as a precautionary measure to
prevent this situation from reversing (NBP 10/7/1998).
As a result of the south-to-north stability constraints, the MEPCO line cannot
be used to deliver any firm power from the south to the north. 12 This
constraint on firm power currently limits the ability of competitive generators
in New England to market their generation to customers in northern Maine. It
is, however, possible to deliver non-firm power from south to north along the
MEPCO line.
NBP and MPS have recently negotiated an agreement to address this south-to-north
transmission constraint. NBP has created a Tie Line Interruption Service,
whereby it will provide MPS with back-up power in the event that the non-firm
energy purchase across the MEPCO line is interrupted. The NBP agreement with
MPS provides for this service to be available to MPS for five years. NBP has
stated that it is prepared to enter discussions with other entities to provide
them with similar firm back-up service (NBP 8/1998). (This issue is addressed
in more detail in Section 6.2)
_______________________________________
11. The line is capable of delivering up to 700 MW of firm power from north to
south (Bustard, Louridas, Brown 1998).
12. HWC notes that "some small amount, perhaps 25 MW - 50 MW," of firm
south-to- north capacity is available on the MEPCO line (HWC and VBPL 11/1998).
Competition and Market Power in the Northern Maine Electricity Market Page 12
2.4 Quantitative Indicators of Market Concentration in Northern Maine
Market Power, Market Concentration and Oligopoly Pricing.
The market power that we address in this study refers to the ability of a firm
or group of competing firms to profitably raise prices above competitive levels
for a sustained period of time. According to economic theory, in a perfectly
competitive market each competitor assumes that market prices are unaffected by
its own actions, ignores the actions of its competitors, and produces as much
of its product that is profitable at prevailing prices.
However, in practice very few firms or markets have the characteristics of
perfect competition. Firms will often modify their pricing and output decisions
in recognition of at least three factors. First, a firm's output level might
affect the price that it can charge for its product. For example, a firm can
withhold capacity in order to increase prices. Second, the availability and
pricing of a product depends not only upon a firm's own actions, but also upon
the interactions between its behavior and the behavior of other producers in the
market. Third, a firm will not necessarily lose many customers as a result of
moderate increases in prices (Joskow 1995). As firms modify their behavior
because of these practical realities of the market, the prices for their
products will deviate from competitive prices.
An oligopoly is a market structure in which a few firms dominate the supply of
a product. Its occurrence is quite common. According to economic theory,
oligopolistic markets can lead to prices that fall within the two extremes of
a perfectly competitive market and an unregulated monopoly market. The pricing
outcome will depend upon the unique factors of the particular market. At one
extreme, oligopoly firms may act competitively resulting in competitive market
prices. At the other extreme, oligopoly firms may develop strategies regarding
the expected behavior of their competitors, or even collude with their
competitors, resulting in prices more like those of an unregulated monopoly.
Thus it is very difficult to accurately predict which pricing strategies will
occur in an oligopolistic market. However, it is important to recognize that
oligopolistic markets have the potential to deviate significantly from
competitive markets.
In general, as a firm's market share increases there is an increased risk that
it will deviate from competitive behavior, and an increased risk of market power
problems. Therefore, market concentration is frequently analyzed as an
indication of the potential for market power. The two most common measures of
market concentration are the "concentration ratio" and the Herfindahl-Hirschman
Index (HHI). No single metric can capture the complexities of the cost
structures and relationships in a real market, but the HHI and concentration
ratio are both useful measures that can serve as a starting point in analyses
of market power. In its merger guidelines, FERC uses the HHI as screening tool
to identify whether market power might be a problem.
Concentration ratios indicate the extent of the market share of the largest
firms in a particular market. For example, the three firm concentration ratio
(abbreviated as "CR3") for a market with ten firms of equal size would be 30
percent. There are currently only three generation companies in the northern
Maine electricity market, so the CR3 is 100
Competition and Market Power in the Northern Maine Electricity Market Page 13
percent. Even after the MPS divestiture there will only be four generation
companies, and the CR3 will be 87 percent. Such high concentration ratios
indicate that the market may be subject to market power problems.
The HHI is defined as the sum of the squares of individual firm's market shares
(expressed as percentages). For example, an industry with ten firms of equal
size would have an HHI of 1000. An industry with five firms of equal size would
have an HHI of 2000.
Department of Justice (DOJ) guidelines for evaluating mergers indicate that at
a market with an HHI of 1000 or less can be viewed as unconcentrated, and
therefore likely to function competitively. A market with an HHI between 1000
and 1800 should be viewed as moderately concentrated. A market with an HHI
above 1800 should be considered highly concentrated, and adverse market power
effects can be presumed. In moderate to highly concentrated markets there may
be market power problems, although whether and to what extent there are problems
depends upon a variety of other factors, for example, barriers to market entry
(DOJ and FTC 1992). These DOJ guidelines have been incorporated into FERC
policy on evaluating market power associated with electric utility mergers (FERC
1996).
HHI Calculations for Northern Maine.
Table 2.3 presents a summary of HHI calculations for various potential future
scenarios in the northern Maine region. The assumptions used in calculating
these HHI results are presented in Appendix B. We look at three factors that
could critically affect the degree of market power in the region: (1) the
divestiture of MPS's generation assets, (2) access to NBP's transmission lines
to import electricity into northern Maine, and (3) a new transmission line
serving the northern Maine region.
Table 2.3 HHI Analysis of Various Scenarios Addressing Market Concentration
Scenario HHI
Divestiture of MPS's generation assets:
1. Before MPS divestiture. (Current conditions.) 2,933
2. MPS divestiture: capacity sold to two buyers.
(Same as MPS divestiture to WPS.) 2,525
3. MPS divestiture: capacity sold to three buyers. 2,397
Assuming MPS divestiture to WPS, with access to NBP's transmission line:
4. HQ (or one NE entity) provided firm transmission access
through NBP. 1,727
5. Two NE entities provided firm transmission access through NBP. 1,527
6. Three NE entities provided firm transmission access through NBP. 1,460
Assuming MPS divestiture to WPS, with construction of new transmission lines:
7. HQ (or single NE entity) provided firm transmission access
through new line. 2,157
8. Two NE entities provided firm transmission access through
new MEPCO line. 1,684
9. Three NE entities provided firm transmission access
through new MEPCO line. 1,526
10. HQ and three NE entities provided firm transmission access
through two new lines. 1,446
Source: See Table B in Appendix B for assumptions used in each calculation.
Competition and Market Power in the Northern Maine Electricity Market Page 14
The first scenario represents the current conditions in the region, before the
divestiture of MPS's generation assets. (This scenario has the same HHI as a
scenario where MPS sells all its generation assets and entitlements to a single
buyer.) The next two scenarios indicate how the HHI would change as a conse-
quence of selling MPS's generation assets to either two or three different own-
ers. (Scenario 2 has the same HHI as a scenario where MPS sells its generation
assets to WPS, and the Wheelabrator-Sherman entitlements are purchased by an
independent generation company.) In all three cases the HHIs are above the
1,800 threshold, indicating that the market would be highly concentrated
regardless of the outcome of the divestiture.
In the first three scenarios we assume that NBP is the only entity that is able
to provide imported power into the northern Maine region. Our Scenarios 4, 5
and 6 present the effects of generation companies from either Quebec or New
England gaining access to the northern Maine market through firm transmission
from NBP. In Scenario 4 we assume that NBP's 90 MW of transmission capacity
into northern Maine is divided into two 45 MW firm increments: one for NBP and
one for a generation company located in Quebec (or New England). In Scenario
5 we assume that NBP continues to reserve 45 MW of transmission capacity for
itself, and allocates the remaining 45 MW in two equal shares to two generation
companies located in New England.13 In Scenario 6 we assume that NBP continues
to reserve 45 MW of transmission capacity for itself, and allocates the remain-
ing 45 MW in three equal shares to three generation companies located in New
England. In all three of these scenarios, the HHI drops to a level that would
be considered moderately concentrated, according to the DOJ HHI guidelines.
Scenarios 7 through 10 present the effects of building new transmission lines
to import additional power into the northern Maine region. Scenario 7 assumes
that a transmission line with 100 MW of firm capacity is installed between MPS
and Hydro-Quebec (or New England), and that only one entity has access to firm
capacity on the line. Scenario 8 is also based on a single new transmission
line, but assumes that two parties have access to firm capacity on the line.
Scenario 9 assumes that three parties have access to a single new transmission
line. Finally, Scenario 10 is a combination of Scenarios 7 and 9; where two new
100 MW transmission lines are constructed, and three entities are provided firm
access to the line from New England. 14
These last HHI results indicate that a single new transmission line is not
sufficient to reduce the HHIs down to the 1,800 threshold, unless that line is
shared by at least two independent parties. It is interesting to note that,
building new transmission lines (Scenarios 7, 8 and 9) does not reduce the HHIs
as much as providing firm transmission
13. A transmission line from MPS to New England is likely to mitigate market
power much more effectively than the same sized line from Hydro-Quebec, because
New England offers northern Maine a competitive wholesale electricity market as
well as a larger number of competitive generation companies. However, in order
to adhere to FERC's guidelines on HHI screening, we only account for those
generation companies in New England that are able to reserve firm transmission
access on the new line. 14. In Scenarios 7 through 10 we assume that the new
transmission lines would have a total thermal capacity of 150 MW, similar to the
lines that are analyzed in Sections 5.2 and 6.3 below. However, we assume that
only 100 MW of these new lines would be available for firm transmission
capacity, due to transmission operating and reliability constraints.
Competition and Market Power in the Northern Maine Electricity Market Page 15
capacity through existing NBP lines (Scenarios 4, 5 and 6), because they are not
as effective in diminishing the large role that NBP can play in the northern
Maine market.
In sum, our HHI analysis indicates that there will be a moderate to high degree
of market concentration in northern Maine under most foreseeable scenarios. The
most important factor influencing this degree of concentration is the control
that NBP has over the imports of generation into the region.
2.5 Limitations to the Herfindahl-Hirschman Index.
It is important to emphasize that we do not recommend that the HHI results here
(or any HHI results) be used in isolation as firm indications of whether market
power will be a problem in northern Maine. Herfindahl-Hirschman Indices are
only rough illustrations of relative market concentration. The HHIs are
presented here simply to help provide an indication of how different scenarios
are likely to affect the degree of market concentration in the region.
In practice, the potential for market power problems in northern Maine may be
even greater than what is indicated by the Herfindahl indices above. Herfindahl
indices do not account for a number of factors that can influence market power
in the electricity industry in general, and do not account for many of the key
factors that lead to market power problems in northern Maine. FERC uses HHI
analysis as a general screening tool to identify potential broad market power
concerns, but recognizes that more detailed analyses are necessary to fully
understand how market power might be applied in a particular situation (FERC
1996).
There are four reasons why the potential for market power problems in northern
Maine may be even greater than what is indicated by the HHI analysis above.
First, the HHI analysis is for the entire northern Maine electricity market, as
opposed to distinct product markets that might have different market power
implications. When assessing the potential for market power in the electricity
industry there are a variety of product markets that should be studied. FERC
recommends that market power studies assess at least the non-firm energy, the
short-term capacity and the long-term capacity markets (FERC 1998). In
addition, the market for ancillary services can provide opportunities for
generation companies to exploit market power, as has been demonstrated by the
recent electricity price spikes in the California market (CAISO 1998).
Second, the HHI analysis does not account for operational constraints on the
generation resources available in northern Maine. If any of the generation
resources or transmission interconnections are unavailable due to maintenance,
forced outages or fueling requirements, then the operators of other resources
will have higher degrees of market concentration. This point is particularly
important in northern Maine where there are so few generation resources and
transmission interconnections.
Third, with so few generation resources available, there is greater potential
for generation companies to "game" the electricity market. When a supply curve
of generation resources is composed of very few power plants, there will be
greater opportunities to raise the bid price for a particular generator above
its variable cost, because the cost of the next generator in the market is
higher still. Minor variations in the operation or bid
Competition and Market Power in the Northern Maine Electricity Market Page 16
price of each plant can have a relatively large impact on the market price for
power. This increased opportunity to game an electricity market with few
generation resources would not be identified by an HHI analysis.
Fourth, there currently is not a competitive wholesale electricity market in
northern Maine. Nor is there a competitive wholesale electricity market nearby
in Quebec or New Brunswick. A fully competitive wholesale electricity market
would significantly reduce the potential for market power abuse by promoting
open access to transmission lines, providing a bidding system that encourages
suppliers to bid their variable operating costs, and increasing opportunities
for new generation companies to enter the market.
2.6 The Importance of Accessing a Competitive Wholesale Electricity Market
Ever since FERC released its "mega-NOPR" in 1995, and its Order 888 in 1996,
FERC has been actively promoting competitive wholesale electricity markets
throughout the US. One of the key ingredients to a competitive wholesale
electricity market is open access, non-discriminatory transmission service for
all generation companies wishing to sell wholesale power. Another key
ingredient is an Independent System Operator that oversees the operation,
planning and construction of transmission lines. A third key ingredient is a
bid-based spot market, where all generation suppliers can bid to sell power to
a central pool on an hourly basis, and generation units are dispatched according
to the lowest bids received.
In every state that we are aware of where retail markets are being opened up to
competition, efforts are also being made to ensure a competitive wholesale
electricity market. California has already established an ISO, and the
California Power Exchange has recently begun operating the electricity spot
market in the state. In New England, the ISO-NE will include a bid-based spot
market, along with market power monitoring and mitigation provisions. Utilities
within the Pennsylvania-New Jersey-Maryland (PJM) power pool have formed an ISO,
which will include a bid-based spot market. ISO's are also being established
or proposed in New York (NY ISO), in the Midwest (Midwest ISO), in the
East-Central region (Alliance ISO), in Texas (ERCOT ISO), in the Southwest
(DesertSTAR), in the Northwest (IndeGO), and in NERC reliability regions known
as Mid-Continent Area Power Pool (MAPP) and Southwest Power Pool (SPP) (EIA
7/1998).
A competitive wholesale electricity market can significantly reduce the risk of
market power problems at both the wholesale and retail level. A competitive
spot market provides a number of benefits over the primary alternative:
bilateral contracts between each buyer and seller. A spot market provides
greater opportunities for new entrants to participate in the market, and to
reach a large number of customers easily and quickly. A spot market provides
electricity buyers greater opportunities for purchasing the lowest-cost
electricity at all times. A spot market also provides real-time, consistent,
reliable and transparent information about market prices and conditions, thereby
promoting efficient market behavior (EIA 9/1998).
An ISO can provide greater division between the owners of the transmission
systems and the owners of generation resources -- thereby reducing the potential
to exploit vertical
Competition and Market Power in the Northern Maine Electricity Market Page 17
market power. An ISO can also establish reliability requirements that apply
equitably to all generation companies serving the market. Without such
reliability requirements, those generation companies holding highly-desirable
capacity during peak periods can exploit capacity shortfalls. An ISO can also
establish market monitoring and market power mitigation mechanisms, to detect
and address any market power problems as they arise.
2.7 Options Available to Reduce Market Power in Northern Maine
It is clear that there are likely to be substantial market power problems in the
northern Maine electricity market -- absent significant changes to the current
conditions. In the remainder of this report, we evaluate various options for
reducing the market power concerns in northern Maine.
We have structured this report according to four strategies that could provide
opportunities for reducing the market power concerns in northern Maine.
- Increase the amount of competition within northern Maine.
- Increase the amount of competitive generation available from New
Brunswick.
- Increase the amount of competitive generation available from Quebec.
- Increase the amount of competitive generation available from New England.
In order to implement any of these strategies, a number of actions may be
necessary. Depending upon the particular strategy, we investigate the following
actions:
1. Increase the number of generators located within northern Maine.
2. Make the wholesale market in New Brunswick more competitive.
3. Convince NBP to provide open-access, non-discriminatory firm
transmission capacity into northern Maine.
4. Make the wholesale market in Quebec more competitive.
5. Build a new transmission line between Hydro-Quebec and MPS.
6. Resolve the south-to-north constraint on the MEPCO transmission line.
7. Build a new transmission line between MPS and MEPCO.
8. Encourage distribution companies in northern Maine to participate in the
ISO-NE market.
Competition and Market Power in the Northern Maine Electricity Market Page 18
3. Increase the Amount of Competition Within Northern Maine.
There are three options for increasing the amount of competitive generation
services within northern Maine: (1) build new power plants, (2) increase the
number of owners of existing power plants in northern Maine through the
divestiture of MPS's assets, and (3) increase the amount of competition at the
wholesale level through institutional means such as an ISO. However, as
discussed below, these options have some important constraints that are likely
to limit their ability to significantly address market power concerns in the
region.
The opportunities to build new power plants in northern Maine are limited by the
size of the electricity market. With existing generation capacity of 135 MW and
import capabilities from NBP of 90 to 200 MW, there is more than sufficient
generation capacity to serve the total peak demand of 123 MW. Consequently,
there is little economic incentive for generation companies to build new power
plants within northern Maine. In addition, there is currently no supply of
natural gas into northern Maine, eliminating the opportunity to construct
natural gas combined-cycle facilities. Furthermore, any new power plant located
in northern Maine would have to pay NBP's relatively high wheel-through
transmission rates in order to export power out of the region. Finally, there
are few target markets in the interconnected neighboring regions where a
generation company might wish to export power to.
The opportunity to increase the number of generation companies located within
northern Maine through MPS's asset divestiture may be limited due to the
condition and small amount of MPS's generation capacity. The responses to MPS's
solicitation indicates that there is significant commercial interest in MPS's
Tinker hydro facility, but little interest in the other generation assets. In
fact, the winning bidder, WPS, indicated that absent the Tinker facility they
would not have bid on any of MPS's assets (Bustard 1998). Therefore, it appears
as though it may be difficult for MPS to sell its generation assets to more than
one buyer.
As currently proposed, the MPS divestiture would potentially allow two companies
to control the generation assets and entitlements currently controlled by MPS.
The assets currently owned by MPS would be controlled by WPS, and the
entitlements to the Wheelabrator-Sherman contract would be controlled by whoever
purchased them in any given year. The Commission may wish to consider
precluding generation companies located in northern Maine from purchasing the
entitlements to the Wheelabrator-Sherman contract, in order to limit the
concentration of generation control in the northern Maine market. However, this
measure is unlikely to significantly reduce the market power concerns in
northern Maine, as indicated by the high HHI result in Scenario 3 in Table 2.3.
In fact, the outcome of MPS's generation asset divestiture is unlikely to
resolve market power concerns, because most of these concerns arise as a
consequence of NBP's control over the transmission lines into the county. In
his testimony on behalf of MPS, Dr. Tabors makes a similar point:
Competition and Market Power in the Northern Maine Electricity Market Page 19
I believe it is important to point out that market concentration in the
region is driven by the existence of New Brunswick and Hydro-Quebec (and
their transmission/supply positions), rather than by variations in the sale
of MPS's assets (Tabors 1998, page 14).
The third option for increasing the degree of competition in northern Maine --
using institutional measures to establish a competitive wholesale market within
the region-- is also limited by the size of the electricity market in northern
Maine. A fully competitive wholesale market would require the creation of an
ISO and the establishment of a spot-market power pooling system. However, an
efficient electricity spot-market requires that there be a sufficient number of
buyers and sellers in the market, and that there be a sufficient number of power
plants to compete to set the market clearing price. In addition, given the
small number of actors in the northern Maine electricity market, it would be
difficult to establish an ISO that is truly independent and that meets all of
the responsibilities of the larger ISOs that are being established elsewhere in
the US.
The T&D utilities in northern Maine are currently investigating options to
increase the competitiveness of the wholesale electricity market in the region.
A "Northern Maine Working Group on Settlement" has been created recently, and
is investigating the establishment and operation of a Bulk Power System
Administrator (BPSA). The Working Group is composed of representatives of EMEC,
MPS, HWC, VBLP, and includes participation by NBP. The structure of the BPSA
and the services it might provide have not yet been determined. The Working
Group is currently investigating whether a BPSA could handle scheduling,
financial settlement, and a day-ahead spot market for all wholesale sellers of
electricity in northern Maine. The spot market could include ancillary
services, and could rely upon a competitive bidding process (MPS 9/1998).
While the BPSA might be an important step toward increasing the degree of
competition in the wholesale electricity market in northern Maine as it
currently exists, it will not provide many of the services and benefits that are
provided by full-scale ISOs such as the ISO-NE. The Working Group itself made
a point of noting that it is not creating an ISO, but rather a bulk power
administrator whose primary responsibilities are to handle financial settlement
between companies and to manage the bidding process (MPS 9/1998).
As currently envisioned, the BPSA will not have all the features and provide all
the functions of typical ISOs. In order to provide the level of competitive
market support provided by a typical ISO, the BPSA would have to:
- have a truly independent governance system;
- ensure open, non-discriminatory transmission access;
- maintain control over the operation of transmission facilities;
- ensure the short-term reliability of grid operations;
- identify transmission constraints on the system and takes operational
actions to relieve constraints;
Competition and Market Power in the Northern Maine Electricity Market Page 20
- maintain pricing policies that promote the efficient use of, and
investment in, generation and transmission;
- establish a market power monitoring system;
- implement market power mitigation measures; and
- establish an alternative dispute resolution process.
It is difficult to envision a northern Maine BPSA that could offer all of these
features, primarily because of the size of the northern Maine electricity
system. Consequently, the Northern Maine Working Group on Settlement should
seriously consider the option of participating in the ISO-NE market to obtain
ISO services. (This option is addressed in more detail in Section 6.4.)
In sum, each of the three options for increasing competition within northern
Maine suffers from limitations due to the size of the electricity market in the
region. It appears that the only practical means of significantly reducing
market power in northern Maine is by looking outside of the region-- by
increasing the opportunities for importing power, and by connecting up to a
competitive wholesale electricity market that is established in a neighboring
region. These options are discussed in the following chapters.
Competition and Market Power in the Northern Maine Electricity Market Page 21
4. Increase the Amount of Competitive Generation Available From New Brunswick.
New Brunswick Power Company currently has roughly 1,100 MW of surplus generation
capacity that could be sold to customers in northern Maine. NBP is currently
the dominant player in the northern Maine electricity market. In order to
increase the amount of competitive generation available from the province of New
Brunswick, it will be necessary for independent power producers (IPPs) to
construct generation facilities within the province.
Until recently, there was little chance of any IPPs building new facilities
within New Brunswick. The province is served entirely by NBP, a vertically
integrated Crown Corporation. In fact, the Electric Power Act of New Brunswick
provides for NBP to be the monopoly supplier of electricity in the province, and
prevents NBP from providing open-access network transmission service (NBP
8/1998).
In 1998 the New Brunswick government opened an investigation into the
opportunities for restructuring the province's electricity market (NB
Restructuring Task Force 1998; NB Department of Natural Resources and Energy
2/1998). The legislative review process is still on-going, with recent public
hearings held by a Legislative Energy Committee, and the government is expected
to develop a policy direction for the future by Spring of 1999 (NBP 10/28/1998).
However, the government has taken a cautious approach to date, and it is not
clear whether it will make any significant changes to the industry within the
foreseeable future. NBP currently has a high level of debt (NB Department of
Natural Resources and Energy 2/1998). This provides the New Brunswick
government and NBP with a powerful incentive to limit the amount of competition
- -- both wholesale and retail -- in the province. MPS recently noted that it
does not expect the retail market in New Brunswick to be opened up to
competition for several years (Bustard, Louridas, Brown 1998).
The New Brunswick government and NBP are currently negotiating with private
companies to develop two separate IPP projects in the province. Tractabel has
proposed a 350 MW gas plant, to be on-line before the end of 2002. Westcoast
has proposed two 250 MW gas units; the first is scheduled to be on-line by the
fall of 2000. Both of these plants are expected to take advantage of the
Maritime and Northeast Natural Gas Pipeline, scheduled to be in-service by
November 1999. Both of these plants are also expected to export some of their
generation to electricity markets in the US (Bustard, Louridas, Brown 1998).
It is not yet clear how much new IPP capacity will be constructed in New
Brunswick and made available to the market in northern Maine. The Westcoast
project is committed to sell its output to NBP for five wither months, the same
period as the northern Maine peak period. The Tractable proposal does not yet
have a planned natural gas pipeline source (HWC and VBLP 11/1998). It is also
not clear whether either of these new IPP developers are planing to market their
power to customers in northern Maine. One of the key factors may be whether NBP
is willing to provide them with firm transmission service to reach northern
Maine.
Competition and Market Power in the Northern Maine Electricity Market Page 22
Nevertheless, these two proposals could offer some new competitive generation
services to the region, and suggest that the New Brunswick government might
allow additional independent power projects in the future. It is also worth
noting that IPP projects located within the province of New Brunswick do not
have to pay NBP's high wheel-through transmission tariff, they can pay the lower
wheel-out tariff. This means that they might have a greater opportunity to
serve the northern Maine market than IPP projects located in Quebec or New
England.
Because of its direct inter-ties with MPS, NBP would seem to provide the easiest
opportunity for the customers in northern Maine to tap into a competitive
wholesale electricity market. However, as described above, the New Brunswick
government is unlikely to open the electricity industry up to either retail or
wholesale competition in the near-term future. Therefore, even if northern
Maine customers can turn to the province of New Brunswick for access to new
generation companies, it will still not be able to access a competitive
wholesale market in New Brunswick -- one of the key ingredients necessary to
mitigate market power concerns in northern Maine.
NBP has recently offered to work with the Commission to identify contractual
transmission arrangements that would help promote a more competitive market in
northern Maine. NBP has also stated that some form of "market regulation" by
the Commission could address some of the concerns about its dominant position
in the region. NBP listed the following regulatory options:
* "Regulation of ancillary services which likely will need to be provided under
contract from NBP and northern Maine generators;
* Limits on the quantity of firm transmission service from NBP to northern Maine
that could be held by any one party;
* A minimum quantity of tie interruption service to insure participation from
ISO-NE parties." (NBP 10/28/1998) 15
Nova Scotia Power Incorporated
Nova Scotia Power Incorporated (NSPI) is another source of generation supply
that could, in theory, reach northern Maine. In the past NSPI has not been an
active marketer of its electricity. In addition, it does not have a large
surplus of generation capacity -- unlike NBP and Hydro-Quebec. NSPI's
generation capacity is roughly 2213 MW and its demand is roughly 1856 MW
(Bustard, Louridas, Brown 1998). This leaves a surplus of only 19 percent, not
much more than is necessary for its own reliability needs.
NSPI has recently indicated that it is interested in selling power to US
markets, including the market in northern Maine. NSPI is connected to northern
Maine through NBP, and there are no other transmission routes between the two
regions. Consequently, NSPI must incur the high wheel-through transmission
tariff imposed by NBP. This is likely to limit NSPI's interest in selling its
power to northern Maine.
15. NBP did not explain how the Commission would have the authority or
jurisdiction to apply this sort of market regulation to NBP.
Competition and Market Power in the Northern Maine Electricity Market Page 23
It is difficult to estimate at this time how much of a role that NSPI is likely
to play in the northern Maine electricity market. It is safe to conclude that
its role is likely to be curtailed somewhat by the dominant role that NBP plays
in transmitting power in the region.
Competition and Market Power in the Northern Maine Electricity Market Page 24
5. Increase the Amount of Competitive Generation Available From Quebec.
5.1 Access Hydro-Quebec Through New Brunswick Power.
In theory, Hydro-Quebec could represent an important source of competitive
generation for customers in northern Maine. It has roughly 4,500 MW of surplus
capacity, it offers low-cost energy from its hydro facilities, and it has
expressed a great deal of interest in recent years in selling power to US
markets.
However, Hydro-Quebec claims that it is precluded from serving the northern
Maine market because of the transmission pricing practices of NBP. In its
response to the Commission's NOI in this docket, Hydro-Quebec states that it is
precluded from scheduling transmission through NBP because the NBP tariff is not
comparable with Hydro-Quebec's tariff. Hydro-Quebec has filed an open-access
transmission tariff with FERC that requires that all intervening transmission
systems offer a service that is comparable with Hydro-Quebec's. Hydro-Quebec
notes the following reasons why its transmission tariff is not comparable with
NBP's:
* NBP's transmission tariff does not permit wheel-in transmission service;
* NBP's transmission tariff is discriminatory in that a different set of rates
apply to wheel-out and wheel-through services; the wheel-through price is 40%
higher than the wheel-out price;
* no regulatory body has jurisdiction over NBP's tariff, and thus it can be
modified unilaterally at NBP's discretion without any remedy available for
transmission customers; and
* NBP has not developed a code of conduct to govern the relationship between its
transmission and its merchant functions (HQ 3/1998).
In personal communications with the company, Hydro-Quebec has indicated that it
has a commercial interest in serving electricity customers in northern Maine.
However, they are not making any reservations on the NBP transmission system to
sell power into northern Maine because of the comparability problem.
Hydro-Quebec claims that the coexistence of reciprocity clauses on both HQ and
NBP tariffs precludes it from selling power across NBP's service territory.
According to HQ, "[i]f Hydro-Quebec were to buy transmission services from NBP,
it would then be compelled to offer comparable access to its own grid to NBP
because of NBP's reciprocity clause. But Hydro-Quebec is forbidden by its own
reciprocity clause to give access to transmission providers who do not offer
comparable services" (HQ 10/1998).
Hydro-Quebec will deliver power at its border with NBP to any generation company
that is interested in purchasing the power. This is the traditional means that
Hydro-Quebec has used to sell power before transmission systems were opened up
in recent years. The recipient generation company can then sell the power into
northern Maine by scheduling transmission services through NBP (HQ 8/1998, HQ
10/1998). In this way, Hydro-
Competition and Market Power in the Northern Maine Electricity Market Page 25
Quebec's power will be available to serve the northern Maine electricity market,
as long as there are marketers willing to purchase and sell it.
NBP does not agree with Hydro-Quebec about the tariff comparability issue. It
believes that Hydro-Quebec is able to wheel power through NBP without violating
the terms of its tariff. NBP refers to one example of an entity that is under
FERC jurisdiction and has used NBP's tariff to wheel electricity from
Hydro-Quebec through NBP. NBP also points out that an independent generation
company within the province of Quebec is fully able to wheel power through NBP's
transmission system (NBP 8/1998). Neither of these examples addresses
Hydro-Quebec's contention that it is not allowed to use NPB's transmission
service to sell its own power into other territories.
MPS also does not agree with Hydro-Quebec about the tariff comparability issue.
MPS believes that Hydro-Quebec is using the comparability issue to prevent NBP
from selling power into Quebec, because Hydro-Quebec cannot sell power into
NBP's service territory (since NBP does not have a wheel-in tariff). MPS also
points out that HQ is using the NBP transmission system to wheel power (both
sales and purchases) to third parties outside of New Brunswick (MPS 8/1998).
Hydro-Quebec disagrees with NBP's and MPS's interpretation of the comparability
issue. Hydro-Quebec points out that there are a few current examples of
Hydro-Quebec purchases that require wheeling power through NBP. However, in
these cases the power marketers have chosen the delivery point to be at the
HQ/NBP border, and have reserved the transmission capacity through NBP
themselves. Hydro-Quebec has not bought transmission services from NBP since
NBP's transmission tariff became effective in January 1998 (HQ 10/1998). In
these instances Hydro-Quebec is not violating the reciprocity clause of its
transmission tariff, because it does not utilize the NBP transmission tariff --
it is essentially just selling the electricity at its border. In addition,
Hydro-Quebec is not using the power marketer to do indirectly what it is
precluded from doing directly -- i.e., selling its own power into the service
territory of an entity with non-comparable transmission tariffs (HQ 8/1998).
In addition, Hydro-Quebec disagrees with NBP's contention that an independent
generation company within the province of Quebec can wheel power through NBP's
transmission system. HQ notes that its reciprocity clause specifies that an
independent generator within Quebec cannot buy transmission services from Hydro
- -Quebec if the transaction also implies wheeling power through a system with
transmission tariffs that are not comparable with Hydro-Quebec's (HQ 10/1998).
Regardless of whether Hydro-Quebec is literally precluded from transmitting
power across NBP's lines, or whether it does not wish to because of the dominant
role played by NBP, the fact is that Hydro-Quebec has been very clear that it
does not intend to market power into northern Maine through the NBP system.
Therefore, it would not be wise to rely upon Hydro-Quebec selling power through
NBP as an option for resolving market power concerns in northern Maine as long
as NBP's tariff is not fully reciprocal and non-discriminatory.
On the other hand, power from Hydro-Quebec's system can be made available to
customers in northern Maine, if Hydro-Quebec sells the power at its border with
New
Competition and Market Power in the Northern Maine Electricity Market Page 26
Brunswick Power. Such a transaction requires that generation marketers in the
region are willing to purchase the Hydro-Quebec power, arrange to have it
transported across NBP's transmission system, and sell it into northern Maine.
5.2 Build a New Transmission Line From Hydro Quebec to Northern Maine.
Exponent and Synapse have spoken with representatives of HQ, MPS, and HWC to
determine the feasibility and potential constraints of a new transmission line
from Hydro-Quebec to northern Maine. This line would bypass NBP, therefore any
power transfers over the line would not be subject to NBP transmission tariffs.
Based on discussions with HQ, MPS and HWC, there are two options to transfer
power directly from HQ to Northern Maine: (1) construct an AC transmission line
through a back-to-back HVDC converter from HQ to MPS; (2) construct a radial
transmission line from HQ to serve isolated loads ("block loads") in Northern
Maine (HQ presently supplies block loads to Citizens Utilities in Vermont). The
first option is reviewed here. The second option would only be available to
serve block loads, and would therefore not address the market power concerns
throughout the northern Maine region.
Technical constraints require a back-to-back HVDC converter for an AC
interconnection between HQ and the existing power grid in Northern Maine. As
such, the most feasible interconnection point for the new line from the HQ
system is at the existing Madawaska back-to-back HVDC converter. Connecting on
the East Side of this converter would avoid the prohibitive cost of a new
back-to-back converter. The existing converter at Madawaska is owned entirely
by HQ and located within the Province of Quebec. Also, based on discussions
with HWC, prior contractual obligations between HQ and NB for the use of this
converter are no longer in force.
Based on discussions with MPS representatives, the most feasible interconnection
point for a new line to Northern Maine is at Flo's Inn substation in the MPS
system. Flo's Inn is a relatively strong substation with nearby voltage support
at Tinker and Beechwood substations.
A new transmission line from Madawaska to Flo's Inn would proceed southwesterly
from Madawaska along the Quebec/New Brunswick border for approximately 25 miles
to the Quebec/Maine border, and then proceed southeasterly for approximately 75
miles to Flo's Inn. The total length of the new line would be approximately 100
miles.
The maximum practical loading of a typical 100-mile 138-kV transmission line is
approximately 150 MVA, based on conductor thermal limits and stability
considerations. Such a line could be designed and constructed for peak ratings
of 150 MVA. Technical studies (power flow, short circuit and stability) would
be required to determine any necessary reinforcements at Flo's Inn. Otherwise,
no operational or physical constraints for this new line have been identified.
The estimated cost of a new 100-mile, 138-kV line is $35.6 million, based on
$356,000 per mile (see Table A.1 in Appendix A). In addition, estimated
substation costs are $3.6 million at Madawaska (including a 150-MVA transformer,
three 345-kV and one 138-kV circuit breakers) and $0.5 million at Flo's Inn
(including two 138-kV circuit breakers).
Competition and Market Power in the Northern Maine Electricity Market Page 27
The total estimated cost of the 100-mile line and substations is $39.7 million.
This cost estimate does not include costs for right-of-way purchase or costs of
any reinforcements at Flo's Inn, if necessary. 16
The total $39.7 million cost for this transmission line translates into an
annual capacity cost of roughly 32 to 48 $/kW-year.17 This is equivalent to an
energy cost of roughly 0.58 to 0.87 c/kWh. In calculating this energy cost we
assume a load factor of 60 percent, and total line losses of 11 percent. If
Hydro-Quebec does not utilize the transmission line as much as 60 percent of the
time, these energy costs will be higher and the economic benefits of the line
will be lower. Our estimates here should be seen as a very rough illustration
of the magnitude of the likely cost of such a transmission line.
In order to determine whether this transmission line is cost-effective, it
should first be compared to the cost to Hydro-Quebec of transmitting power
through NBP. NBP currently charges roughly 34 $/kW-year to transmit power
across its lines, which suggests that the new line is not necessarily a more
cost-effective option for serving the electricity market in northern Maine.
In addition, NBP's ability to alter its transmission rates poses some
uncertainty to the economics of a line from HQ to northern Maine. If NBP were
to significantly lower its wheel-through transmission rate, then the HQ-MPS line
would be less economic -- partly because Hydro-Quebec would have a less
expensive option, and partly because the lower NBP transmission rate might bring
a greater number of competitors into the northern Maine market. In its
testimony seeking authorization for sale of its generation assets, MPS describes
the ability that NBP has to competitively price its transmission services in
this way, and therefore to influence the interest and ability of other entities
to build new transmission lines into northern Maine (Bustard, Louridas, Brown
1998).
Furthermore, in order for this new transmission line to be in Hydro-Quebec's
economic interest, the cost of the line would have to be recovered from the
revenues that Hydro-Quebec can make on the sales to the northern Maine
electricity market. Given the small size of the market in northern Maine, it
is not at all certain that Hydro-Quebec would be able to make enough sales to
that region sufficient to recover the costs of this transmission line.
Hydro-Quebec's American transmission subsidiary, TransEnergie US, is interested
in serving the northern Maine electricity market. They are currently
investigating the cost of constructing a transmission line from HQ to northern
Maine. They expect to have a preliminary cost estimate for such a line in the
near future. While they could not provide any early results as of the date of
this study, they did indicate that they are investigating newer technologies
that might cost less than those we used in our estimates above (TransEnergie US
8/1998). Once they have completed a cost estimate, they will then
16. The estimated cost of a 150-MVA back-to-back HVDC converter is far in
excess of $100 million.
17. Here we assume a fixed charge factor of 12 percent. The low end of the
range is based on the full 150 MW thermal capacity of the line. The high end
of the range is based on the assumption that only 100 MW of the firm capacity
will be available due to reliability and stability constraints.
Competition and Market Power in the Northern Maine Electricity Market Page 28
investigate whether the market in northern Maine is desirable enough to warrant
the cost of building the new transmission line.
Competition and Market Power in the Northern Maine Electricity Market Page 29
6. Increase the Amount of Competitive Generation Available From New England.
6.1 Access New England Through New Brunswick Power.
New England offers the greatest opportunity to increase the number of
competitive generators serving northern Maine.18 All of the New England states
are opening up their retail electricity markets to competition. Power
developers have recently requested interconnection studies to build a total of
nearly 30,000 MW of new capacity in New England to serve the evolving
competitive market (ISO-NE 6/1998).19 New England utilities and others are
establishing the ISO-NE, which should significantly increase the degree of
wholesale electricity competition in the region. In fact, New England offers
northern Maine the only existing competitive wholesale electricity market to tap
into in the short-term.
NBP is currently connected to New England through the MEPCO transmission line.
In addition, BHE is planning to build a new transmission line that would connect
it with NBP. BHE expects that the line would have roughly 300 MW of firm
transmission capacity. Bangor Hydro is building the line for the purpose of
selling firm transmission service on the line. In fact, it may wait to obtain
an interested purchaser of the line before constructing it (BHE 9/1998). BHE
points out that if this new line were built it would allow new entrants to make
firm transmission reservations to export power from New Brunswick to New
England. Such new entrants would potentially provide additional competitive
resources to serve northern Maine (BHE 10/1998).
Any generation company from New England wishing to serve northern Maine would
have to transmit its power across NBP. It is likely that some generation
companies in New England will be hesitant to sell power to northern Maine
because of the influential role that NBP plays in the transmission of power and
the lack of regulatory oversight over NBP's transmission services. Generation
companies might be concerned that NBP can unilaterally adjust transmission rates
and can discriminate against certain companies. Furthermore, the high
wheel-through transmission rate might create a barrier for some generation
companies in New England trying to reach northern Maine. Even if NBP does not
display a tendency to adjust rates or discriminate against any companies, the
risk that it could do so may be enough to deter some generation companies.
In order for policy-makers in Maine to be assured that NBP will provide open
access, non-discriminatory transmission service through its territory, NBP
should take the following four steps.
1. NBP should follow-through with its offer to contractually agree to fixed
terms and conditions of its transmission tariff. The same terms and conditions
should be made
18. Although northern Maine is part of New England, we use the term "New
England" here to refer to the electricity market within the existing NEPOOL
grid.
19. These are requests for interconnection studies only; it is unlikely that
all of this generation capacity will be constructed.
Competition and Market Power in the Northern Maine Electricity Market Page 30
available to all generation companies purchasing transmission services from NBP.
These measures should remove the uncertainty regarding whether NBP would
unilaterally modify the terms and conditions of its tariffs or discriminate
against some generation companies while favoring others.
2. NBP should demonstrate that its transmission tariffs are comparable with
FERC's pro-forma transmission tariff. FERC's pro-forma tariff spells out many
terms and conditions for how transmission services should be provided to
competing generation companies. For example, it requires terms and conditions
that pertain to quality of transmission service. The pro-forma tariff addresses
procedures for how competing generation companies can queue up for service when
transmission capacities are limited. The FERC pro-forma tariff represents a
benchmark that indicates the extent to which a transmission company will provide
open access, non-discriminatory transmission services. If the NBP transmission
tariff is comparable to this benchmark, then generation companies and regulators
in New England will have greater certainty that NBP will provide acceptable
transmission services.
3. NBP should follow-through with its offer to cap its transmission rates until
a regulatory body is established in New Brunswick with jurisdiction over
transmission tariffs. A fixed transmission rate should remove the uncertainty
regarding whether NBP would unilaterally modify its rate or discriminate against
some generation companies while favoring others
4. NBP should demonstrate that the terms and conditions of the transmission
services that it provides to others are comparable to the terms and conditions
of the transmission services that it takes for itself. In particular, it should
demonstrate whether the existing discrepancy between its wheel-through and
wheel-out transmission rates is cost-justified. If the discrepancy is not
cost-justified, then NBP should eliminate it. A discrepancy in transmission
rates that is not cost-justified suggests that NBP favors its own generation
services over others, and is likely to deter competitive generation companies
from using NBP's transmission services. Even if the discrepancy in price is
small, the perception of favoritism or discrimination might discourage some
generation companies.
If NBP were to take all of these steps, then generation companies and regulators
in New England can be confident that the NBP system can be used to transmit
power to the competitive electricity market in northern Maine. However, the
ability of any New England generation company to serve customers in northern
Maine will depend upon the limitations of the transmission capacity between the
two regions. This issue is discussed in more detail in the following sections.
6.2 Improve the South-to-North Flow on the MEPCO Transmission Line
As described in Section 2.3, the existing MEPCO transmission line is not capable
of carrying any firm capacity from the south to the north, as a result of
stability and reliability constraints. However, NBP has recently established
a Tie Line Interruption Service, whereby it will provide generation companies
with back-up power in the event that the non-firm energy purchase from the south
across the MEPCO line is interrupted.
Competition and Market Power in the Northern Maine Electricity Market Page 31
NBP recently signed a five-year contract with MPS to provide the Tie Line
Interruption Service, and has indicated that this same service will be made
available to any other entity. There are no reservation fees or capacity fees
required for the service; it would be a pay-as-you-go service. The back-up
service would be available at an energy-only price that reflects the costs to
NBP plus 20 percent (NBP 8/1998).
The Tie Line Interruption Service does not require any capacity fees, nor any
spinning reserve fees, because NBP believes that it currently has sufficient
capacity to provide this service without building any new power plants. It
expects that the Service will likely be very rarely needed, because it would
only be required when the net flow on the MEPCO line is south-to-north. This
has only occurred for one or two hours over the past few years. A net south-to
- -north flow could occur at any time of the year - not necessarily at peak hours
when capacity is most tight. Therefore, NBP believes that it will have suffic-
ient capacity available for the Tie Line Interruption Service in those few in-
stances when the net flow on the MEPCO line is south-to-north (NBP 10/7/98). 20
The NBP Tie Line Interruption Service could provide an important opportunity for
generation companies in New England to reach the northern Maine electricity
market, and to tap into the ISO-NE spot market for power. The establishment of
this service means that the MEPCO transmission line is likely to be the most
immediate and practical option available for increasing the amount of
competition in the northern Maine electricity market. The only uncertainty
remaining is whether this service will be available after five years from now,
and what the terms will be at that time.
However, the extent to which the MEPCO line can be used to import power into
northern Maine from New England will depend upon the degree to which NBP is
committed to provide transmission service to all interested generation companies
on a non-discriminatory basis. Since the MEPCO line does not currently connect
to northern Maine directly, transactions with New England generation companies
or with the ISO-NE will still have to pass through New Brunswick. The
conditions necessary to assure that generation companies in New England can
receive non-discriminatory open access transmission services from NBP are
described in the previous section.
The proposed transmission line between BHE and NBP might also help mitigate the
south-to-north transmission constraint on the MEPCO line, by providing another
route for power exchanges between New England and New Brunswick (BHE 10/1998).
Similarly, the tap into the MEPCO transmission line proposed by Bowater paper
company (see below) might help to mitigate these constraints. However, it is
not possible to quantify the extent to which these new transmission projects
would mitigate the constraint without conducting power flow studies.
20. The Tie Line Interruption will only be provided subject to the availability
of generation resources on the New Brunswick Power system. Consequently, the
purchaser of this Service bears the risk that sufficient generation capacity
might not be available at the time the Service is needed. However, if NBP's
assessment of the frequency with which this service will be needed is correct,
this risk is likely to be small. In addition, New Brunswick Power's capacity
of 4116 MW currently exceeds its peak load of 2989 MW by roughly 38 percent
(Bustard, Louridas, Brown 1998).
Competition and Market Power in the Northern Maine Electricity Market Page 32
6.3 Build a New Transmission Line from NEPOOL to Northern Maine.
Estimated Cost of a New Transmission Line
The most likely opportunity for a new transmission line to link northern Maine
with the rest of New England would be to run a new line between MPS and the
existing MEPCO transmission line. In 1984, Power Technologies Inc. (PTI)
conducted a load-flow study of such a line (PTI 1984). We utilize the results
of the PTI study to estimate the appropriate configuration of a tap into the
MEPCO transmission line. We then use a more recent study to estimate the cost
of that particular configuration (Acres 1996).
The existing MEPCO line is 345 kV and runs from Keswick, New Brunswick to
Orrington, Maine. The PTI study investigated an interconnection between MPS's
69-kV Mullen substation and a new substation at Haynesville on the MEPCO line.
Figure 1 in Appendix C shows a single-line diagram of this proposed
interconnection, which consists of the following facilities:
(1) An extension to Mullen substation containing:
* One 138-kV and one 69-kV circuit breaker
* One 69/138-kV transformer
(2) A 138-kV Mullen-Haynesville transmission line of about 25 miles
(3) A substation at Haynesville containing:
* A 345-kV bus
* Three 345-kV and one 138-kV circuit breakers
* A 138/345-kV transformer
The PTI study showed a peak flow of 37 MVA (36.6 MW and 1.1 Mvars) on the
proposed Mullen-Haynesville interconnection under one set of 1985 peak load
conditions with 56.5 MW of cogeneration added to the MPS system. The study also
showed a peak flow of 49 MVA (48.7 MW and 1.9 Mvars) under another set of 1985
load conditions with 56.5 MW of cogeneration added.
Based on a peak flow of 50 MVA in the year 2000 and an average annual increase
of 3% over a thirty-five-year expected transmission-line life, normal peak flow
in the year 2035 would be approximately 150 MVA on the proposed interconnection.
MPS's response to the Commission's NOI in this docket includes system one-line
diagrams proposing two alternatives for the interconnection (MPS 3/1998). MPS's
alternative II proposes a 25-mile 138-kV line from Mullen to Haynesville, a
150-MVA autotransformer at Haynesville, a 50-MVA autotransformer at Mullen, and
associated substation equipment. The normal peak flow for this alternative
would be limited to 50 MVA by the Mullen autotransformer.
MPS's Alternative I proposes a rebuild of 41-mile Line 6910, upgrading from 69kV
to 138kV, in addition to the equipment proposed in Alternative II. Line 6910 is
one of two
Competition and Market Power in the Northern Maine Electricity Market Page 33
existing 69-kV lines from Mullen to Flo's Inn. During telephone
discussions with MPS, it indicated that a normal peak flow of 150 MVA on the
proposed interconnection would require the rebuild on Line 6910 in order to
increase the transfer capability between Mullen and Flo's Inn. It is noted that
the 1984 PTI study did not consider flows above 50 MVA on the proposed
interconnection.
Cost estimates in this report are provided in two stages for the proposed
Haynesville-Mullen interconnection. Stage 1, which is adequate for 50 MVA
normal peak flow on the interconnection, is the MPS Alternative II. Stage 2,
which increases the normal peak capability to 150 MVA, is the rebuild of Line
6910, MPS's Alternative I.
Figure 2 in Appendix C shows the transmission line configuration selected for
the cost estimate: a 138-kV shielded single-circuit line, H-frame wood-pole
construction.
Alternative configurations for 138-kV overhead lines include the following:
wood-pole H-frame; wood-pole H-frame with compact phase spacing; wood-pole with
compact delta arrangement; steel pole with vertical arrangement; steel pole with
compact vertical arrangement; steel pole with delta arrangement; and steel pole
with compact delta arrangement. In 1996, Acres International investigated the
costs of these configurations for 115-kV transmission in Connecticut (Acres
1996). Acres reported the wood-pole H-frame configuration to have the lowest
cost. Other recent studies have shown that, for most overhead line
applications, treated wood remains the most cost-effective material in terms of
both initial and total life-cycle costs, when compared to steel, fiberglass, or
concrete (Electrical World 1997).
Table 6.1 gives the construction cost estimate for the proposed
Haynesville-Mullen interconnection. The construction cost estimate is $13.6
million for Stage 1, and $15.5 million for Stage 2, leading to a total cost of
$29.1 million. The total $29.1 million cost for this transmission line
translates into an annual capacity cost of roughly 23 to 35 $/kW-year, depending
upon how much firm transmission capacity is available after accounting for
reliability and stability concerns. 21 This is equivalent to an energy cost of
roughly 0.44 to 0.66 c/kWh. 22
21. Here we assume a fixed charge factor of 12 percent. The low end of the
range is based on the full 150 MW thermal capacity of the line. The high end
of the range is based on the assumption that only 100 MW of firm capacity will
be available due to reliability and stability constraints.
22. Here we assume a load factor of 60 percent and total losses of 3.5 percent.
Competition and Market Power in the Northern Maine Electricity Market Page 34
Table 6.1 Construction Cost Estimate-Proposed Haynesville-Mullen
Interconnection
Stage 1 Cost
Extension to the Mullen Substation $1,030,000.
25-mile 138-kV line ($356K/mile) $8,936,780.
Haynesville Substation $3,550,000.
Regulatory Cost $118,000.
Subtotal - Stage 1 $13,634,780.
Stage 2 (rebuild of Line 6910)
42-mile 138-kV line ($356K/mile) $14,669,136.
Mullen termination $365,000.
Flo's Inn termination $430,000.
Regulatory Cost & Permit Fees $50,000.
Subtotal - Stage 2 $15,514,136.
TOTAL $29,148,916.
Source: See Appendix C.
More details on these construction cost estimates are provided in Appendix C.
Table C.2 gives the construction cost estimate per mile for the proposed 138-kV
line. This estimate is based on the estimate given in the Acres report for a
115-kV single-circuit, overhead, H-frame, wood-pole transmission line (Acres
1996). Cost estimates in the Acres report have been updated in Table C.2 for
138-kV construction. As shown, the cost is $356,047 per mile, excluding the
cost for purchasing right-of-way. Table C.3 gives construction cost estimates
for the substations at Haynesville, Mullen, and Flo's Inn. Sample material
costs are given in Table C.4.
Similar Tap Line Proposed by Bowater Paper Company
The Bowater paper company (formerly Great Northern Paper) has proposed the
construction of an 11.7-mile, 115-kV, 225 MVA, transmission line from its mill
in East Millinocket to a new substation and tap on the MEPCO line at Mattaseunk
(north of Chester). The estimated cost of this tap line, provided by Duke
Engineering & Services, is $250,000 per mile, which is based on single wood-pole
construction with the three phases in a delta configuration on post insulators.
For our cost estimate of the 138-kV line in Table 6.1, we assume an H-frame
wood-pole construction, with a cost of $356,000 per mile. We choose this
configuration because it is consistent with standard construction in New England
and its superior performance under storm loading (wind and ice, as well as
lightning).
Following a modernization program, Bowater's peak load is estimated at 195 MW.
Bowater proposes to purchase an average of 71 MW via its proposed tap line, with
the remaining load served by Bowater generation. It is expected that the
south-to-north transfer capacity over the MEPCO line would be increased by the
improved voltage support that the proposed Bowater tap line provides. However,
power-flow studies are required to determine the increase in transfer capacity.
Competition and Market Power in the Northern Maine Electricity Market Page 35
The New Line Might Not Resolve the South-to-North Transmission Constraint.
MPS claims that if the new line were connected at Haynesville, existing south-to
- -north transfer limitations would not be improved (MPS 3/1998). In particular,
following a disturbance resulting in the loss of the largest single generating
unit, the new Mullen-to-Haynesville line would likely trip out of service.
In the opinion of HWC, south-to-north transfer limitations would be improved if
the new line were connected at Orrington, rather than Haynesville (HWC 6/1998).
However, the length of a new line from Mullen to Orrington would be greater than
50 miles. Operational studies (power flow and stability) would be required to
examine these operational issues further.
Therefore, all of the issues discussed in Section 6.2 would continue to pertain
to this new transmission line. Anyone wishing to obtain firm capacity on the
new line would have to arrange for NBP's Tie Line Interruption Service.
Consequently, the new MEPCO tap line -- which was intended to bypass the NBP
transmission system and dominant role in the region -- would be subject to some
degree of NBP intervention after all.
Technical Concerns With the New MEPCO Tap Line.
The PTI study identified two potential problems with this new line. One is the
possibility of a large power flow through the MPS system should the Keswick end
of the 345-kV MEPCO line inadvertently open while both the Orrington end and the
tap at Haynesville remain closed. The other is the likelihood of high voltages
in the southern part of the MPS system should the Keswick and Orrington ends of
the MEPCO line be opened before the tap at Haynesville is opened. The PTI study
concluded that special steps in the design of the protection and control of the
345-kV MEPCO line are warranted to overcome these problems.
MPS also raises reliability and safety issues associated with the new MEPCO tap
line. It notes that the line could cause MPS's entire system to become radial
and would require at least two of the three interconnections with NBP to be
closed (MPS 3/1998). However, MPS also notes that while these issues are of
"paramount concern" for the company, it could utilize some form of relay
protection in order to maintain its connections with NBP and avoid making its
entire system radial. MPS does not expect that this protection would require
any substantial expense that would undermine the potential for building the new
MEPCO transmission tap (MPS 8/1998).
Construction and Payment of the New Line.
MPS and MEPCO are the two likely developers of a new MEPCO tap line. MEPCO
would be acting on behalf of its member companies -- BHE, CMP and MPS. Another
option is for a non-profit entity to develop the new MEPCO tap line. Such an
entity would require less financing costs than MPS or MEPCO (HWC & VBLP
11/1998).
MPS has not expressed an interest in constructing the MEPCO tap line. It does
cite the line as the most commonly analyzed route for bringing power into
northern Maine from New England, but it also raises a number of reliability and
stability concerns about such a line (Bustard, Louridas, Brown 1998; MPS
3/1998).
Competition and Market Power in the Northern Maine Electricity Market Page 36
A CMP representative has expressed some interest in the potential business
opportunities of the MEPCO tap line. CMP could build the line through their
affiliation with MEPCO, and could use it to sell transmission capacity to
generation companies seeking to transmit power into or out of northern Maine.
However, CMP has not studied this issue in depth, and does not currently have
any plans to do so (CMP 1998).
BHE has no economic or business interest in the tap from the MEPCO line to
northern Maine, because such a line is not necessary given that NBP can supply
the load with its existing transmission system. In addition the Tie Line
Interruption Service removes the need for such a line, and northern Maine is not
a region that BHE serves (BHE 9/1998; BHE 10/1998).
It appears as though the line would have to be paid for by either MPS or MEPCO,
depending upon who is the primary developer of the line. The costs of the new
transmission line would then be rolled into the existing transmission rates of
the project developer.
ISO-NE is currently developing protocols regarding who should pay for the
construction of new transmission lines that serve the NEPOOL grid. The MEPCO
tap line would likely be considered as a new transmission line constructed for
the purpose of connecting ISO-NE with a neighboring system. If so, then a
portion of the costs on the New England side of the line might be paid by
transmission companies within the ISO-NE. However, this is not a certainty.
In sum, it appears as though the majority, if not the entirety, of the costs of
the new MEPCO transmission line would have to be borne by the project developer,
which could be MPS, MEPCO or potentially a non-profit entity.
While the estimated cost of this new transmission line (23-35 $/kW-year) is less
than or close to the cost of transmitting power across the NBP system (34
$/kW-year), it is not at all clear whether such a line would be economically
justified. The primary uncertainty is whether the new transmission line would
be used enough to cover its costs, given that there already is sufficient
transmission capacity available from NBP to serve the northern Maine market.
6.4 Encourage the Northern Maine Distribution Companies to Participate in the
ISO-NE Market.
A new transmission line from MPS to MEPCO could increase the degree of
competition in northern Maine at both the retail and wholesale level by allowing
generation companies to enter the market without having to wheel power through
NBP. However, in order to enjoy all of the benefits available from the
competitive wholesale generation market in New England, MPS, HWC, VBLP and EMEC
would have to also participate in the ISO-NE market.
Additional study will be necessary to determine what will be required of the
northern Maine T&D utilities in order to participate in the ISO-NE market. We
assume that at a minimum this will require transferring from the Maritime Pool
control area and into the NEPOOL control area.
Competition and Market Power in the Northern Maine Electricity Market Page 37
Participating in the ISO-NE would create the following benefits for the
electricity market in northern Maine:
* Retail and wholesale electricity purchasers in northern Maine would have
access to the wholesale spot market in New England, providing an important
alternative to bilateral contracts. As described in Section 2.6, a spot market
provides greater opportunities for new entrants, increases the ability of
purchasers to obtain the lowest-cost electricity, and promotes more efficient
market behavior by providing consistent, reliable and transparent information
on a real-time basis.
* Generation companies located in northern Maine would have access to the
electricity market in New England. This access would provide important
opportunities to sell outside of northern Maine, and it would provide
opportunities to purchase power from the pool to complement or back-up the power
sales within northern Maine.
* Generation companies seeking to sell Standard Offer services in northern Maine
would have access to the wholesale spot market in New England.
* The Commission and the distribution companies in northern Maine would be able
to take advantage of the market power mitigation measures that are currently
being established by ISO-NE. These measures would provide (a) a mechanism for
identifying and resolving market power problems as they arise in northern Maine,
(b) lessons and insights from the identification and resolution of market power
problems in New England, and (c) a benchmark for assessing the severity and
frequency of market power problems that arise in northern Maine.
There will be some costs associated with participating in the ISO-NE. In
addition to the $500 annual membership fee, participants are allocated indirect
costs associated with the ISO operation, including regional network service
costs, congestion costs, and ISO operating expenses (ISO-NE 10/1998, CMP 1998).
The transaction-based costs are allocated on the basis of load, so the costs for
the Maine transmission and distribution utilities will be relatively small.
It is possible for MPS, HWC, VBLP and EMEC to participate in the ISO-NE market
without becoming members of NEPOOL. 23 If these utilities participate in the
ISO-NE, there does not appear to be many additional benefits available from
joining NEPOOL as well. The only obvious benefit is that by being a member of
NEPOOL these utilities would be able to play a role in the ISO decision-making
process, allowing them to influence policies regarding transmission pricing,
planning and siting, spot market operation and protocols, and reliability
requirements. However, their representation in the ISO-NE is likely to be very
small given the size of their loads.
In the past, the Commission required MPS to conduct periodically a study of the
costs and benefits of becoming members of NEPOOL. These NEPOOL Entry Studies
found that the costs to MPS of joining NEPOOL were greater than the benefits to
MPS. The
23. Load serving entities that own generation must be a member of NEPOOL in
order to participate in the ISO-NE. After the MPS divestiture, none of these
utilities will own generation capacity.
Competition and Market Power in the Northern Maine Electricity Market Page 38
most recent NEPOOL Entry Study was filed with the Commission in December 1992,
and found that the costs of joining NEPOOL exceeded the benefits by roughly $0.9
to $1.3 million per year. The study looked at the costs and benefits associated
with three aspects of joining NEPOOL: operation and dispatch, transmission and
wheeling, and administration expenses such as billing and management. The study
found that costs exceeded benefits in each of these three areas.
MPS has not conducted a study of the costs and benefits of participating in
ISO-NE. Through personal communications with company representatives, MPS noted
that it would be difficult to perform an updated NEPOOL Entry Study at this time
because of all the uncertainties and unresolved issues associated with the
transition from NEPOOL to ISO-NE.
We believe that this is an opportune moment for conducting a study of the costs
and benefits of MPS (as well as HWC, VBPL and EMEC) participating in ISO-NE.
The results of earlier NEPOOL Entry Studies are no longer relevant. The three
aspects studied by MPS in the past -- dispatch, transmission and administration
- -- will be fundamentally different under the ISO-NE, and could easily have
benefits that exceed costs. More importantly, now that retail competition is
to be introduced in northern Maine there may be significant market power
benefits of participating in ISO-NE that should be considered by the T&D
utilities and the Commission.
A study of participating in the ISO-NE should investigate the following issues:
* What are the costs, benefits and implications of northern Maine utilities
participating in ISO-NE? What are the benefits to northern Maine in
terms of reducing market power concerns?
* What are the costs, benefits and implications of northern Maine utilities
becoming members of NEPOOL?
* To what extent could the existing MEPCO line be used by utilities in
northern Maine to access the ISO-NE?
* What are the costs, benefits, and implications of building a new
transmission link between MPS and NEPOOL, in order for northern Maine
utilities to participate in the ISO-NE market?
New England offers electricity customers in northern Maine the only opportunity
to access a competitive wholesale electricity market in the foreseeable future.
Therefore, we believe that a study of the costs and benefits of participating
in the ISO-NE market should be one of the highest priorities of the Commission
in its efforts to address market power issues in Maine.
Competition and Market Power in the Northern Maine Electricity Market Page 39
7. Conclusions and Recommendations
7.1 Synthesis of Our Analysis
Under current conditions the electricity market in northern Maine is likely to
be subject to market power problems. The primary causes of market power in the
region are: the isolation of the market, the small size of the market, the lack
of access to a competitive wholesale electricity market, and the dominant role
played by NBP in the region.
Role of New Brunswick Power
While many of these causes can be addressed by the strategies and options
discussed in the study, the greatest cause of market power concern -- New
Brunswick Power -- poses a significant challenge. NBP has the ability to
exploit its role as the only provider of transmission into northern Maine,
thereby limiting the amount of competitive generation suppliers that can reach
the area. Not only does it have control over the current transmission into
northern Maine, it can also play an influential role in many of the solutions
that we have considered in this study:
* Hydro-Quebec is currently not willing to sell power into the northern
Maine market, because NBP's transmission tariff is not comparable with
its own.
* NBP has the ability to reduce the economic benefits of building a new
transmission line to MPS -- either from Hydro-Quebec or from New England
-- by reducing the price of its wheel-through tariff. NBP's ability to
influence the construction of a new transmission line allows it to
maintain its dominant role over transmission in the northern Maine
region.
* Generation companies in New England may be reluctant to sell power into
the northern Maine market, due to the high NBP wheel-through tariff and
NBP's ability to unilaterally modify the terms and conditions of
transmission service.
* Those generation companies that choose to sell power into the northern
Maine market over the existing MEPCO line would have to buy back-up Tie
Line Interruption Service from NBP.
* Those generation companies that wish to sell power into the northern
Maine market over a new transmission line would have to buy back-up Tie
Line Interruption Service from NBP.
* The only option that we have considered in this report that does not
require some role by NBP is that of increasing the number of competitive
generation companies within northern Maine. However, the potential to
substantially reduce market power through this option is quite limited,
as discussed in Section 3.
In recent months, NBP has made some important offers to mitigate concerns about
its influence on the electricity market in northern Maine. These include (a)
providing a Tie Line Interruption Service that can provide back-up power to
mitigate the south-to-north constraint on the MEPCO line, (b) providing fixed
terms and conditions for its
Competition and Market Power in the Northern Maine Electricity Market Page 40
transmission tariff, including a price cap, (c) unbundling its operations and
providing services under a code of conduct, (d) working with the government of
New Brunswick to establish a process to regulate New Brunswick Power's
transmission services, (e) working with the Commission to develop regulations
and contractual arrangements that would lead to market conditions satisfactory
to the Commission, and (f) supporting the efforts of the Northern Maine Working
Group in developing a BPSA for the region (NBP 10/28/1998).
These proposals from NBP are significant and might resolve the issues regarding
its dominant role in the northern Maine electricity market. However, there
remains some uncertainty as to the extent to which these measures will fully
address the market power concerns discussed in this study. For example:
* The Tie Line Interruption Service is currently available for only five
years. Uncertainty regarding the following years might pose a barrier
to some generation companies interested in the northern Maine market.
NBP's surplus generation is likely to be reduced after five years, and
the Company might not be willing to offer such favorable terms for the
Service with less surplus generation available.
* It is unclear whether the transmission price cap and fixed terms and
conditions proposed by NBP will apply equally to all transmission users.
It is unclear whether they will conform to the standards of FERC's
pro-forma transmission tariff. It is also unclear whether NBP will
provide competing generation companies with transmission prices, terms
and conditions that are comparable to those of the transmission services
that it takes for itself.
* While unbundling of the NBP merchant activities and transmission services
is a positive step, codes of conduct can be difficult to monitor and
enforce. Most states that are implementing retail competition, including
Maine, are encouraging or requiring electric utilities to divest their
generation assets instead of relying upon codes of conduct to prevent
vertical market power problems. In addition, the Maine Public Utilities
Commission has no jurisdiction over codes of conduct that apply to NBP.
* While the BPSA might provide an important settlement function in the
northern Maine electricity market, it is not expected to have all of the
features and provide all of the functions of a typical ISO. It is not
yet clear whether the BPSA will be sufficiently independent of New
Brunswick Power. In fact, NBP has expressed an interest in providing the
generation bidding function and the wholesale settlement functions of the
BPSA (MPS 10/29/1998).
Conditions for a Competitive Electricity Market in Northern Maine
In sum, there are three broad conditions that will help to promote a fully
competitive retail electricity market in northern Maine. These conditions are
outlined in turn below. If any one of these inter-dependent conditions is not
met, then the region will continue to be subject to market power concerns.
1. Northern Maine should be provided with open access, non-discriminatory
transmission services -- including transmission services for imported power.
Such import
Competition and Market Power in the Northern Maine Electricity Market Page 41
transmission services could either be provided through NBP or through a new
transmission line to the rest of New England. If NBP is relied upon for import
transmission services, then it should demonstrate its commitment to open access,
non-discriminatory services by taking the following four steps.
* NBP should follow-through with its offer to contractually agree to fixed
terms and conditions of its transmission tariff. The same terms and
conditions should be made available to all generation companies
purchasing transmission services from NBP.
* NBP should follow-through with its offer to cap its transmission rates
until a regulatory body is established in New Brunswick with jurisdiction
over transmission tariffs.
* NBP should demonstrate that its transmission tariffs are comparable with
FERC's pro-forma transmission tariff.
* NBP should demonstrate that the terms and conditions of the transmission
services that it provides to others are comparable to the terms and
conditions of the transmission services that it takes for itself. In
particular, it should demonstrate whether the existing discrepancy
between its wheel-through and wheel-out transmission rates is cost-
justified. If the discrepancy is not cost-justified, then NBP should
eliminate it.
2. Northern Maine should have access to a fully competitive wholesale
electricity market. Such a market could, in theory, be achieved by either
participating in ISO-NE, developing a fully competitive market through the BPSA,
or promoting wholesale competition within the Maritime Pool. Participating in
ISO-NE appears to be the most effective option, because the latter two options
will not provide the level of wholesale competition necessary to address the
market power concerns in northern Maine.
Access to ISO-NE would be easiest to obtain through the existing MEPCO line.
This would require open access non-discriminatory transmission services through
the NBP system (condition #1 above), because that is the only transmission
access that MPS has to the MEPCO line.
Access to ISO-NE could also be obtained through a new transmission line from
MEPCO to MPS. However, the most likely prospect for such a line would not
resolve the south-to-north transmission constraint on the existing MEPCO line.
In addition, it is highly uncertain whether such a line would be economically
justified, given that there already is sufficient transmission capacity
available from NBP to serve the northern Maine market. On the other hand, a new
transmission line from MEPCO to MPS might be necessary to access ISO-NE if NBP
does not provide open access non-discriminatory transmission services, or if the
transmission capacity between NBP and MPS is not sufficient to carry the load
between northern Maine T&D utilities and ISO-NE.
In order for the northern Maine T&D utilities to participate in ISO-NE, they
would have to secure sufficient Tie Line Interruption Service to support south-
to-north transmission over the MEPCO transmission line. This will be the case
even if a new transmission line from MEPCO to MPS is constructed. Any
uncertainties about the terms and conditions
Competition and Market Power in the Northern Maine Electricity Market Page 42
of the Tie Line Interruption Service, including uncertainties regarding the
prospects for services five years in the future, would have to be resolved.
3. A sufficient number of generation companies should be able to reach northern
Maine T&D utilities. If the previous two conditions are met, then it is safe
to conclude that there will be a sufficient number of generation companies
willing and able to serve the northern Maine market. Hydro-Quebec would be
likely to play an active role in the region, and connection with ISO-NE should
provide sufficient opportunities from competitive generation companies in New
England.
7.2 Recommendations
Given the potential for market power problems in northern Maine, we recommend
that the Commission address the issue from a number of angles. The two
overarching goals of the Commission should be: (1) to encourage the distribution
companies within northern Maine to obtain access to a fully competitive
wholesale electricity market, and (2) to promote open access, non-discriminatory
transmission services for power imported into the northern Maine system. To
help achieve these goals, we recommend the Commission pursue the following
specific actions:
1. Conduct further research. There are a number of areas where further
research will shed light on some important issues raised in our study. For
example, the Commission should:
* Require the Northern Maine Working Group on Settlement to conduct a
thorough review of the costs and benefits of participating in the ISO-NE
market. The review should account for the benefits of reducing market
power concerns in northern Maine. The study should also include an
analysis of the advantages and disadvantages of participating in ISO-NE
versus developing and implementing the BPSA. 24
* Review TransEnergie's study of constructing a transmission line from
Hydro-Quebec to MPS. An initial draft of the study is due to be
completed soon.
* Investigate a new transmission line between New England and MPS. The
Commission should begin discussions with MPS, CMP, BHE, and MEPCO to
investigate the advantages and disadvantages of constructing such a line,
as well as who would act as project developer for the line.
2. Encourage NBP to provide truly non-discriminatory, open-access transmission
service. The four steps necessary for NBP to demonstrate that such
transmission service will be provided in the near term are: (a) NBP should
contractually agree to fixed terms and conditions of its transmission
tariff for all generation companies; (b) NBP should cap its transmission
rates; (c) NBP should demonstrate that its
24. The northern Maine Working Group on Settlement has recently discussed the
option of participating in ISO-NE, and has begun corresponding with the ISO-NE
to inquire about the implications of participation. (MPS 10/21/1998).
Competition and Market Power in the Northern Maine Electricity Market Page 43
transmission tariffs are comparable with FERC's pro-forma transmission
tariff; and (d) NBP should demonstrate that the terms and conditions of the
transmission services that it provides to others are comparable to the
terms and conditions of the transmission services that it takes for itself.
3. Oversee the development of the BPSA in northern Maine. The first order of
business should be to determine whether the services offered by the BPSA
would be better provided by participating in the ISO-NE market instead.
If the BPSA turns out to be the best or most practical approach, the
Commission should ensure that it is governed and operated in a way that (a)
is independent of the T&D utilities and NBP, (b) mitigates the market power
concerns in the region, and (c) includes market power monitoring and
prevention measures similar to those adopted by ISO-NE.
4. Encourage the distribution companies in northern Maine to participate in
the ISO-NE market, if further research indicates that participation is
feasible and the benefits are likely to exceeds the costs.
5. Work with NBP to follow-up on its offers to establish regulations and
contractual arrangements that would lead to market conditions satisfactory
to the Commission.
6. Participate in the New Brunswick government's legislative review process
regarding the restructuring and associated regulation of the electricity
market in New Brunswick. The Commission can play an important role in
informing the New Brunswick government about the conditions necessary to
make the New Brunswick market sufficiently competitive to support the
northern Maine electricity market.
7.3 The Costs and Benefits of Addressing Market Power in Northern Maine.
Our conclusion that there is likely to be significant market power concerns in
northern Maine for the foreseeable future raises two critical questions for the
Commission:
* Are the negative implications of market power in northern Maine likely
to be so great that the Commission should not open that market up to
retail competition?
* If the Commission does open the northern Maine market up to retail
competition, are the costs associated with the market power mitigation
measures worth the benefits enjoyed in terms of reduced market power?
The first question is difficult to answer. It requires a comparison of (a) the
benefits of retail competition relative to continued regulation, with (b) an
estimate of the increase in electricity costs that northern Maine customers are
likely to experience as a result of market power. The benefits of retail
competition are speculative and depend upon a variety of factors that are
difficult to anticipate. An estimate of the likely price increase resulting
from market power is beyond the scope of this study. At this time, all we can
safely say is that if retail competition is introduced in northern Maine without
implementation of some of the important market power mitigation measures
identified in this report, electricity customers are likely to pay prices that
are significantly higher than those available from a competitive electricity
market.
Competition and Market Power in the Northern Maine Electricity Market Page 44
The second question may be a little easier to answer -- with additional
information. The only two measures discussed above that are likely to require
significant costs are the new transmission lines between MPS and Hydro-Quebec
or New England, and participating in the ISO-NE market. The Commission should
be able to access the on-going Hydro-Quebec study regarding a new transmission
line connection with MPS. A new study of the costs and benefits of
participating in ISO-NE, and a new study of the costs of a new transmission link
between NEPOOL and MPS, would provide important information regarding the
advantage of those options relative to the disadvantages of market power in
northern Maine. Such studies would be essential in answering the second
question raised above.
Competition and Market Power in the Northern Maine Electricity Market Page 45
8. References
Acres International Corporation (Acres) 1996. Life-Cycle Cost Studies for
Overhead and Underground Electric Transmission Lines, Amherst, NY, July.
Bangor Hydro Electric (BHE) 10/1998. Comments on Review Draft of "Competition
and Market Power in the Northern Maine Electricity Market," October 28, 1998.
BHE 9/1998. Personal communication with Jeff Jones, Manager of Power Supply,
September 2.
Bustard 1998. Prefiled Direct Testimony, representing Maine Public Service
Company, MPS Petition for Authorization for Sale of Generation Assets, before
the Maine Public Service Commission, Docket No. 98-584, August.
Bustard, Louridas, Brown 1998. Prefiled Direct Testimony, representing Maine
Public Service Company, MPS Petition for Authorization for Sale of Generation
Assets, before the Maine Public Service Commission, Docket No. 98-584, August.
California Independent System Operator (CAISO) 1998. Preliminary Report on the
Operation of the Ancillary Services Markets of the California Independent System
Operator, prepared by the Market Surveillance Committee of the California ISO,
August.
Central Maine Power Company (CMP) 1998. Personal communication with Steve
Garwood, August 17, September 2 and October 5.
Clark and Cote 1998. Direct Testimony of John L. Clark and Gilles Cote, before
the Maine Public Utilities Commission, on behalf of Houlton Water Company,
Docket No. 98-584, October 28, 1998.
Department of Justice (DOJ) and Federal Trade Commission (FTC) 1992. Statement
Accompanying Release of Revised Merger Guidelines, April.
Eastern Maine Electric Cooperative (EMEC) 10/1998. Comments on Review Draft of
"Competition and Market Power in the Northern Maine Electricity Market," October
30, 1998.
EMEC 3/1998. EMEC's Response to the Commission's NOI, Docket No. 97-586, March
5.
Econosult 1998. Issues Report: Maine Public Service Company Generation Assets
Divestiture Plan, prepared for the Maine Public Service Commission, January.
Electrical World 1997. Transmission Structures-Find the Most Cost-effective
Options, December, pp.38-43.
Energy Information Administration (EIA) 9/1998. Challenges of Electric Power
Industry Restructuring for Fuel Suppliers, DOE/EIA-0623.
EIA 7/1998. The Changing Structure of the Electric Power Industry: Selected
Issues, DOE/EIA-0620.
Competition and Market Power in the Northern Maine Electricity Market Page 46
Federal Energy Regulatory Commission (FERC) 1998. Revised filing Requirements
Under Part 33 of the Commission's Regulations, Notice of Proposed Rulemaking,
Docket No. RM98-4-000, April 16.
FERC 1997. Order Accepting for Filing and Suspending Proposed Tariffs,
Establishing Optional Procedures and Consolidating Dockets, Docket Nos.
EC97-5-00, ER97-412-000 and ER97-413-000, July 16.
FERC 1996. Inquiry Concerning the Commission's Merger Policy Under the Federal
Power Act: Policy Statement, Order no. 592, Docket No. RM96-6-000, December 18.
Houlton Water Company and Van Buren Light and Power District (HWC & VBLP)
11/1998. Comments on Review Draft of "Competition and Market Power in the
Northern Maine Electricity Market," November 3, 1998.
Hydro-Quebec (HQ) 10/30/1998. Comments on Review Draft of "Competition and
Market Power in the Northern Maine Electricity Market," October 30, 1998
HQ 8/1998. Personal communications with Katherine Bert, August 17 and August 24.
HQ 3/1998. Hydro-Quebec's Response to the Commission's NOI, Docket No. 97-586,
March 13.
Independent System Operator New England (ISO-NE) 10/1998. Discussions with Jim
Sinclair of ISO-NE, August 12 and October 6.
ISO-NE 6/1998. Interconnection Study Status, posted on ISO-NE web site
www.iso-ne.com, as of June 25, 1998.
Paul Joskow 1995. Horizontal Market Power in Wholesale Power Markets,
Massachusetts Institute of Technology, August.
Maine Department of Attorney General (ME AG) 9/1998. Memorandum from Francis
Ackerman regarding telephone conversation with Darrell Bishop and Arden Trenholm
of NBP, September 25 1998; and Memorandum from Francis Ackerman regarding
telephone conversation with Gordon Weil, September 24 1998.
Maine Department of the Attorney General and Maine Public Utilities Commission
1998. Market Power In Electricity: A Study of Market Power Issues Raised by the
Prospect of Retail Competition in the Electricity Industry, presented to the
Joint Standing Committee on Utilities and Energy of the Maine Legislature,
Interim Report, January 13.
Maine Public Service Company (MPS) 10/29/1998. Minutes of Meetings of the
Northern Maine Working Group on Settlement, describing meetings and
teleconferences held on October 2 and October 23.
MPS 10/26/1998 Comments on Review Draft of "Competition and Market Power in the
Northern Maine Electricity Market," October 26, 1998
MPS 10/21/1998. Letter to Robert Charpentier, President and Chief Executive
Officer of ISO-NE, regarding potential for northern Maine T&D utilities joining
ISO-NE.
Competition and Market Power in the Northern Maine Electricity Market Page 47
MPS 9/1998. Minutes of Meetings of the Northern Maine Working Group on Settle-
ment, describing meetings and teleconferences held on August 13, August 31, and
September 3.
MPS 8/1998. Personal communications with representatives of MPS including: a
letter from Steve Johnson to Tim Woolf dated 8/2198; and a phone conversation
with Steve Johnson, Bill St. Cyr, and Frederick Bustard on 8/13/1998.
MPS 3/1998. MPS's Response to the Commission's NOI, Docket No. 97-586, March 2.
MPS 1992. NEPOOL Entry Study, New England Electric Power Pool Agreement Review
Pursuant to Chapter 390, January.
Maine Public Utilities Commission (MPUC) 2/1998. Maine Public Service Company
Divestiture of Generation Assets, Order, Docket No. 97-670, February 20.
MPUC 1/1998. Public Utilities Commission Study of Northern Maine Connections
to the Electricity Grid, Notice of Inquiry, Docket No. 97-586, January 28.
Munster, F 1998. Comments on Review Draft of "Competition and Market Power in
the Northern Maine Electricity Market," October 27, 1998
New Brunswick Department of Natural Resources and Energy 10/1998. Comments on
Review Draft of "Competition and Market Power in the Northern Maine Electricity
Market," October 28, 1998
New Brunswick Department of Natural Resources and Energy 2/1998. Electricity
in New Brunswick Beyond 2000, Discussion Paper, February.
New Brunswick Power (NBP) 10/1998. Comments on Review Draft of "Competition and
Market Power in the Northern Maine Electricity Market," October 28, 1998
NBP 10/1998. Personal communication with Darrell Bishop and Arden Trenholm,
October 7, 1998.
NBP 8/1998. Letter and attachments from Darrell Bishop, Director of Bulk Power
Marketing at NBP to Tim Woolf.
NBP 3/1998. NBP's Response to the Commission's NOI, Docket No. 97-586, March 3.
NBP 1/1998. Tariff for Out and Through Point-to-Point Transmission Service,
Effective Date: January 1 1998.
New Brunswick Restructuring Task Force 1998, Electricity in New Brunswick and
Options for Its Future, Co-Chaired by David Hay and Donald Savoie, July.
New England Power Pool (NEPOOL) 1997. Market Monitoring and Reporting and
Market Power Mitigation Proposal, December.
Northern Maine Working Group on Settlement 11/1998. Northern Maine BPSA Draft
Framework Document, submitted to the Commission on November 12, 1998.
Competition and Market Power in the Northern Maine Electricity Market Page 48
Power Technologies, Inc (PTI) 1984. Load Flow Study of the 396 Tap for Maine
Public Service Company, J.W. Feltes & H.K. Clark, Schenectady, NY, March.
Tabors 1998. Prefiled Direct Testimony, on behalf of Maine Public Service
Company, MPS Petition for Authorization for Sale of Generation Assets, before
the Maine Public Service Commission, Docket No. 98-584, Tabors, Caramanis &
Associates, August.
TransEnergie 3/1998. TransEnergie's Response to the Commission's NOI, Docket No.
97-586, March 19.
TransEnergy US 8/1998. Personal communication with John Miller, August 19.
Weil 4/1998. Electricity Trade: The Problem of New Brunswick Power, April.
Weil and Howe 5/1998. Personal communications with Gordon Weil and David Thorn,
representing Houlton Water Company and Van Buren Light and Power District.
Weil and Howe 3/1998. Houlton Water Company and Van Buren Light and Power
District's Response to the Commission's NOI, Docket No. 97-586, March 4.
Competition and Market Power in the Northern Maine Electricity Market Page 49
Appendix A. Map of Northern Maine and Regional Interconnections
A map of northern Maine and interconnections with utilities in the region is
attached. This map is taken directly from Exhibit BLB II-1 of Bustard, Louridas
and Brown 1998.
(Picture)
Appendix A Page A-1
Appendix B. Herfindahl-Hirschman Index Calculations
Table B. HHI Analysis of Various Scenarios Addressing Market Concentration.
Share of
Total Total
Owner Power Source Capacity Capacity HHI
(mw)
1. Before MPS Divestiture
MPS Hydro - Tinker 33.5 15% ----
MPS Other (Hydro, Diesels) 14.6 6% ----
MPS Wheelabrator-Sherman 18.1 8% ----
MPS Total ---- 66.2 29% 864
AVEC Wood 32.0 14% 202
AEI Wood 37.0 16% 270
NBP Imports 90.0 40% 1597
Total ---- 225.2 100% 2933
2. After MPS Divestiture: Two Buyers
Buyer 1 Hydro - Tinker 33.5 15% ----
Buyer 1 Other (Hydro, Diesels) 14.6 6% ----
Buyer 1 Total ---- 48.1 21% 456
Buyer 2 Wheelabrator-Sherman 18.1 8% ----
AVEC Wood 32.0 14% 202
AEI Wood 37.0 16% 270
NBP Imports 90.0 40% 1597
Total ---- 225.2 100% 2525
3. After MPS Divestiture: Three Buyers
Buyer 1 Hydro - Tinker 33.5 15% 221
Buyer 2 Other (Hydro, Diesels) 14.6 6% 42
Buyer 3 Wheelabrator-Sherman 18.1 8% 65
AVEC Wood 32.0 14% 202
AEI Wood 37.0 16% 270
NBP Imports 90.0 40% 1597
Total ---- 225.2 100% 2397
4. HQ Provided Firm Transmission Access Through NBP
WPS Hydro - Tinker 33.5 15% ----
WPS Other (Hydro, Diesels) 14.6 6% ----
WPS Total ---- 48.1 21% 456
Buyer 2 Wheelabrator-Sherman 18.1 8% ----
AVEC Wood 32.0 14% 202
AEI Wood 37.0 16% 270
NBP Imports 45.0 20% 399
HQ Imports 45.0 20% 399
Total ---- 225.2 100% 1727
5. Two NEPOOL Entities Provided Firm Transmission Access Through NBP
WPS Hydro - Tinker 33.5 15% ----
WPS Other (Hydro, Diesels) 14.6 6% ----
WPS Total ---- 48.1 21% 456
Buyer 2 Wheelabrator-Sherman 18.1 8% ----
AVEC Wood 32.0 14% 202
AEI Wood 37.0 16% 270
NBP Imports 45.0 20% 399
NEPOOL Imports 22.5 10% 100
NEPOOL Imports 22.5 10% 100
Total ---- 225.2 100% 1527
Appendix B Page B-1
Table B. Continued
6. Three NEPOOL Entities Provided Firm Transmission Access Through NBP
WPS Hydro - Tinker 33.5 15% ----
WPS Other (Hydro, Diesels) 14.6 6% ----
WPS Total ---- 48.1 21% 456
Buyer 2 Wheelabrator-Sherman 18.1 8% ----
AVEC Wood 32.0 14% 202
AEI Wood 37.0 16% 270
NBP Imports 45.0 20% 399
NEPOOL Imports 15.0 7% 44
NEPOOL Imports 15.0 7% 44
NEPOOL Imports 15.0 7% 44
Total ---- 225.2 100% 1460
7. HQ Provided Firm Access Through New 100 mw HQ/MPS Transmission Line
WPS Hydro - Tinker 33.5 10% ----
WPS Other (Hydro, Diesels) 14.6 4% ----
WPS Total ---- 48.1 15% 219
Buyer 2 Wheelabrator-Sherman 18.1 6% ----
AVEC Wood 32.0 10% 97
AEI Wood 37.0 11% 129
NBP Imports 90.0 28% 766
HQ Imports 100.0 31% 946
Total ---- 325.2 100% 2157
8. Two NEPOOL Entities Provided Firm Access Through New 100 mw MEPCO Line
WPS Hydro - Tinker 33.5 10% ----
WPS Other (Hydro, Diesels) 14.6 4% ----
WPS Total ---- 48.1 15% 219
Buyer 2 Wheelabrator-Sherman 18.1 6% ----
AVEC Wood 32.0 10% 97
AEI Wood 37.0 11% 129
NBP Imports 90.0 28% 766
NEPOOL Imports 50.0 15% 236
NEPOOL Imports 50.0 15% 236
Total ---- 325.2 100% 1684
9. Three NEPOOL Entities Provided Firm Access Through New 100 mw MEPCO Line
WPS Hydro - Tinker 33.5 10% ----
WPS Other (Hydro, Diesels) 14.6 4% ----
WPS Total ---- 48.1 15% 219
Buyer 2 Wheelabrator-Sherman 18.1 6% ----
AVEC Wood 32.0 10% 97
AEI Wood 37.0 11% 129
NBP Imports 90.0 28% 766
NEPOOL Imports 33.3 10% 105
NEPOOL Imports 33.3 10% 105
NEPOOL Imports 33.3 10% 105
Total ---- 325.2 100% 1526
10. HQ and Three NEPOOL Entities Provided Firm Access Through Two New Lines
WPS Hydro - Tinker 33.5 8% ----
WPS Other (Hydro, Diesels) 14.6 3% ----
WPS Total ---- 48.1 11% 128
Buyer 2 Wheelabrator-Sherman 18.1 4% ----
AVEC Wood 32.0 8% 57
AEI Wood 37.0 9% 76
NBP Imports 90.0 21% 448
HQ Imports 100.0 24% 553
NEPOOL Imports 33.3 8% 61
NEPOOL Imports 33.3 8% 61
NEPOOL Imports 33.3 8% 61
Total ---- 425.2 100% 1446
Appendix B Page B-2
Appendix C. Transmission Cost Estimates
Figure 1 shows a single-line diagram of the proposed Haynesville-Mullen
interconnection, which consists of the following facilities:
(1) An extension to Mullen substation containing:
* One 138-kV and one 69-kV circuit breaker
* One 69/138-kV transformer
(2) A 138-kV Mullen-Haynesville transmission line of about 25 miles
(3) A substation at Haynesville containing:
* A 345-kV bus
* Three 345-kV and one 138-kV circuit breakers
* A 138/345-kV transformer
Appendix C Page C-1
(Picture)
Figure 1 - Proposed Mullen-Haynesville Interconnection
Appendix C Page C-2
Figure 2 below shows the transmission line configuration selected for the cost
estimate: a 138-kV shielded single-circuit line, H-frame wood-pole construction.
(Picture)
Figure 2 - 138kV Shielded Single-Circuit Line
H-Frame Wood-Pole Construction
Appendix C Page C-3
Exhibit 99(u)
STATE OF MAINE
PUBLIC UTILITIES COMMISSION
In Re Market Power Study ) Docket No. 97-877
)
FINAL REPORT
I. INTRODUCTION
Following enactment on May 29, 1997 of historic electric restructuring
legislation, 1 the Legislature directed the Department of the Attorney General
("Department") and the Public Utilities Commission ("Commission") "to conduct
a study of market power issues raised by the prospect of competition in the
electric industry," and to provide "a final report of their findings and
recommendations no later than December 1, 1998." 2 This report, presented to the
Joint Standing Committee on Utilities and Energy jointly by the Department and
the Commission, responds to that legislative mandate. The report includes
specific legislative recommendations. Proposed draft legislation designed to
implement those recommendations will follow.
A. The Statute
Maine's electric industry restructuring statute opens the State's retail
electricity markets to competition as of March 1, 2000, enabling consumers to
choose among competing energy providers. The underlying premise of the statute
is that competitive markets result in higher quality products at lower prices.
In addition to initiating retail choice, the new law:
- - requires investor-owned utilities to divest most generation assets, while
allowing them to retain transmission and distribution ("t&d") assets
1 P.L. 1997 ch. 316, codified at 35-A M.R.S.A. sections 3201-3217.
2 P.L. 1997 ch. 447 Part B sections B-1, B-6.
-2-
- preserves state regulation of electricity delivery systems, i.e., t&d
services
- permits regulated t&d companies to engage in retail marketing through
unregulated affiliates, subject to a code of conduct and a market share
limitation
- imposes a Renewable Portfolio Standard ("RPS"), requiring competitive
providers to demonstrate that 30% of their supply portfolio derives from
renewable resources (as defined)
- ensures the availability of default "standard offer" retail service for
consumers who prefer not to select a competitive provider.
B. The Context
Electric industry restructuring initiatives are proceeding at the federal
level and in numerous states in the United States. Internationally,
restructuring is well advanced in several countries, including New Zealand, the
United Kingdom and Norway. Because of the size and economic importance of the
energy sector, these restructuring efforts are unprecedented both in their scale
and in the scope of their economic implications.
Until relatively recently, it was generally accepted that competition was
simply not feasible in an industry dominated by monopoly fiefdoms. Historically,
the U.S. electric industry developed as a patchwork of isolated,
vertically-integrated monopoly utility systems, each generating and distributing
energy to retail customers in a discrete service territory. Retail rates were,
and in most U.S. jurisdictions still are, subject to regulation by state Public
Utilities Commissions. As interconnections between utility systems were forged
to enhance reliability, and regional grids took shape, a wholesale market
developed. Today, utilities purchase electricity in the wholesale market from
other utilities and from independent energy producers. Interstate wholesale
rates and transmission rates are subject to federal regulation, specifically by
the Federal Energy Regulatory Commission ("FERC").
-3-
Maine and several other New England states (and numerous other states
across the country) are opening retail markets to competition on varying
schedules. At the same time, FERC is moving to introduce competition into
wholesale markets. The agency now permits energy wholesalers to charge
market-based rates if they can demonstrate that they do not possess, or have
adequately mitigated, market power in the relevant market. The New England Power
Pool ("NEPOOL"), the regional utility consortium, currently has an application
pending before FERC for authority to charge market-based rates.
As wholesale and retail restructuring moves forward regionally and
nationally, the shape and character of the industry will be altered in important
respects:
- vertical integration will diminish as states mandate or encourage
separation of generation and transmission, and new, independent
generation facilities enter the market
- federal and state regulation of transmission and distribution will
remain, reflecting the fact that proliferation of competing power
delivery systems is impracticable
- rates for wholesale and retail energy will be determined by supply and
demand in competitive markets.
C. The Study
The primary obstacle to the successful introduction of competition into
electricity markets remains monopoly or oligopoly market power. Some economists
predict that competitive markets will produce significantly lower prices for
consumers, 3 as well as more generalized economic benefits. Others warn that
these potential benefits will not be realized unless wholesale and retail
markets are structured at the outset in such a way as to avoid control by a few
large competitors. 4
3 For example, one study predicts that Maine residential rates will drop by
approximately 3 cents/kwh (from 12.6 to 9.5 cents), or 24%, in real dollars over
the period 1996-2015. H. Chernoff & G. Sanchez, The Impact of Industry
Restructuring on Electricity Rates, July 1998, Table ES.1.
4 Consumer Union & Consumer Federation of America, The Residential Ratepayer
Economics of Electric Utility Restructuring: Balancing All the Costs and
Benefits, July 1998 at 49 (market power could disproportionately victimize
residential consumers, raising prices).
-4-
Recognizing that market power poses a serious threat to the success of its
restructuring initiative, the Legislature immediately followed enactment of the
restructuring statute with passage of a law directing the Department and the
Commission jointly to conduct a comprehensive study of market power issues. In
particular, the Department and the Commission were directed to examine the
following:
- the effects of altering the system of electric power dispatch from a
cost-based to a bid-based system
- the potential for market concentration or horizontal market power
- the potential for vertical market power arising from the ownership or
control of transmission and distribution systems by entities selling or
marketing electric power
- the extent to which imbalances of supply and demand create opportunities
for the unreasonable exercise of market power
- the significance of existing or potential transmission system constraints
and the ownership and control of transmission ties
- the significance of the isolation of portions of the transmission and
distribution grid from other portions of the grid, in particular from
those portions of the grid currently controlled by NEPOOL
- the reasonable geographic areas and markets in which market power could
be exercised
- the extent to which market power in relevant markets is within the scope
of federal regulatory jurisdiction; and
- the approaches taken in other states to address market power issues.
Our report addresses each of these aspects of the problem of market power in an
appropriate context. Specifically, the report is organized in four substantive
parts: vertical market power issues (Part III); horizontal market power in New
England (Part IV); horizontal market power in northern Maine (Part V); and
market power in renewables (Part VI).
-5-
Broadly speaking, the purpose of this report is to assess the extent to
which the persistence of market power in restructured markets is likely to
frustrate statutory goals, and prevent Maine consumers from receiving the
benefits of competition. Based on our assessment, in accordance with the
legislative directive, we offer recommendations with respect to needed
modifications and additions to the restructuring statute. Some aspects of market
power are beyond Maine's jurisdictional reach. We therefore also identify and
discuss issues which the Department and the Commission are addressing, or may
address, in federal regulatory or court proceedings.
While we are confident that the analysis of market power issues offered
below provides a sound basis for our legislative recommendations, it should be
noted that our analysis is necessarily open to debate, and remains subject to
adjustment in light of intervening developments. Many of the issues discussed
are highly controversial. The structure of electricity markets in Maine and
New England, and the rules governing and the conditions surrounding them, are
evolving rapidly. Moreover, none of the issues discussed in this report has
been litigated or adjudicated, and our joint analysis should not be viewed as
binding in any respect on the Commission in the context of any pending or future
proceeding. 5
Before turning to the substance of our analysis, we provide a brief
introduction to market power in electricity, and explain why existing antitrust
law cannot by itself provide a sufficient remedy.
D. Market Power in Electricity
5 Parties to any pending or future proceeding at the Commission are entitled to
full due process rights to test both the facts assumed and the analysis
developed in this report. Moreover, it is entirely possible that intervening
events may require adjustment of our factual or analytical conclusions. It is
noteworthy that even as the final drafts of this report were in preparation,
there were developments at FERC and in discussions among stakeholders in
northern Maine which clearly hold significant implications for market power
analysis.
-6-
Market power may be either horizontal or vertical. Horizontal and vertical
market power both carry special risks in electricity markets, because of the
nature of electricity as a commodity, because of prevailing market rules, and
because of the necessary coexistence of competition and regulation in
restructured markets.
Horizontal market power is the ability of a single dominant firm or group
of dominant firms to profit by raising prices above competitive levels. The
higher the market shares of the individual firms, and the smaller the number of
firms competing in the market, the more the market will be subject to the
exercise of horizontal market power, and the less consumers will receive the
benefits of higher quality and lower price.
Horizontal market power in electricity may be subject to a greater degree
of abuse than in other industries, for three reasons. First, electricity is the
ultimate perishable commodity; it cannot be easily stored in large quantities,
but must be produced for immediate consumption. Thus, supply generally cannot
be shifted from one time period to another to remedy scarcity. Second, retail
demand for electricity is relatively inelastic. This means that demand is
generally unresponsive to price fluctuations, and is not easily shifted from one
time period to another. 6
Finally, costs of production vary widely among facilities and fuel types.
To the extent they are competitive, supply-side bids into the spot market, which
will be the primary wholesale price-setting mechanism in New England, will be
based substantially on variable costs. Under prevailing market rules governing
bid-based dispatch, each facility or block of power will be bid
6 Demand elasticity is much greater in the industrial than in the residential
sector. We believe that further study is warranted to determine whether specific
legislative or regulatory initiatives could promote demand elasticity generally
as a means to mitigate horizontal market power. Supplier prices at wholesale and
retail can be disciplined to the extent that retail customers are enabled to
react in real time to hourly price developments. This requires access to
appropriate metering, communications and energy management (automated switches
activated by price information) technologies. Enhanced access to off-grid
generation sources would also be desirable. Finally, facilitating customer
aggregation might promote demand elasticity, and would strengthen demand-side
bargaining power. The Department and the Commission may offer recommendations
in this regard at a later time.
-7-
into the market, and the bids ranked from lowest to highest, for dispatch in
that order. All suppliers receive the price bid by the last increment of supply
necessary to meet demand in a given hour. As a result, competition between a
relatively small number of competitors at the margin may be critical in setting
price. 7
Vertical market power, in contrast, derives from a single firm's integrated
presence at more than one level of commerce. A firm which combines generation
or retail marketing of electric power with provision of t&d services is
vertically integrated. Where a vertically integrated firm is a regulated
monopolist at one level of commerce, as t&d companies are, it may possess an
enhanced ability to project its monopoly power to another level. For example,
a t&d company might possess the ability to confer advantage on its retail
marketing affiliate by providing it with preferential treatment, or free or
subsidized services. Such an exercise of vertical market power would enable the
affiliate to compete unfairly, and might deter would-be competitors from
entering and permit the affiliate to build a dominant position in the retail
market.
E. The Limits to Antitrust
The options available to antitrust enforcement agencies to remedy vertical
or horizontal market power in newly restructured markets are limited and often
inadequate. In essence, there are only four opportunities for antitrust
intervention. First, a proposed merger or acquisition which significantly
increases horizontal concentration (and reduces competition) is subject to
effective challenge under state or federal antitrust laws. Second, collusive
agreements or combinations among competitors (e.g. price fixing) are illegal
under antitrust law, and subject to both criminal and civil enforcement. Third,
exclusionary conduct by a monopolist can be attacked
7 Current NEPOOL market rules allow only for supply-side bids. However, ISO-New
England, Inc., which will operate the spot market, favors introduction of
demand-side bidding to mitigate market power. The Commission and the Department
support this initiative.
-8-
as a monopolization offense, though such cases are notoriously lengthy,
cumbersome and difficult to prove. Finally, unfair methods of competition may
be challenged under the Unfair Trade Practices Act. 8
It remains that preexisting market power, short of monopoly, which is
entrenched in the structure of the industry and exercised unilaterally, is
beyond the reach of the antitrust laws. In view of the limitations of antitrust
enforcement, it is essential that Maine ensure, as far as the reach of its
jurisdiction will allow, that newly opened electric power markets are
competitively structured on day one. If the wholesale generation market or the
retail market embark on competition with highly concentrated structures, or
structures otherwise susceptible to the exercise of market power, antitrust
enforcers will have relatively limited remedial options, and consumers may well
pay higher prices.
8 10 M.R.S.A. sections 1101 (contracts or combinations in restraint of trade),
1102 (monopolization offenses), 1102-A (mergers and acquisitions); 5 M.R.S.A.
section 207 (unfair methods of competition). Each of these provisions has a
federal counterpart.
-9-
II. EXECUTIVE SUMMARY
A. Vertical Market Power Issues
Vertical market power may be brought to bear in the electric power industry
when a utility operates a monopoly interstate transmission system and also
engages in business as a generator of energy (transmission-derived vertical
market power); or when a local transmission and distribution company (t&d) is
also a retail marketer of energy (distribution-related vertical market
power). Such an integrated enterprise can exercise vertical market power in two
principal ways: by affording preferential treatment to the competitive
affiliate; and by shifting costs to the regulated entity. Vertical market power
threatens the ultimate success of restructuring efforts by raising the barriers
to entering newly competitive markets.
Maine has addressed transmission-derived vertical market power in the
restructuring statute by requiring utilities to divest generation assets,
thereby severing the link between generation and transmission. However, New
England's electric grid spans six states, and its wholesale markets are
therefore subject to federal jurisdiction. Although some voluntary
divestitures have occurred, no other state in the region has mandated
divestiture. Accordingly, Maine must to a large extent rely on federal remedies
to combat vertical market power in these markets. The FERC has implemented open
access transmission rules, and has approved the establishment of an independent
system operator (ISO) to operate the New England grid. The Commission and the
Department are actively engaged in proceedings at FERC in which vertical
market power issues have arisen.
In contrast, Maine possesses plenary legislative jurisdiction to address
distribution-related vertical market power, which affects retail markets. In the
restructuring statute, the Legislature adopted a dual approach, enacting a code
of conduct to police the relationship between the t&d and its marketing
affiliate, and a provision limiting the market share attainable by the affiliate
in the t&d service territory. This solution represented a compromise between the
contending positions of the utilities, which opposed the market share limitation
and aspects of the code of conduct, and the Commission, which advocated a
complete ban on affiliate marketing in the t&d service territory.
A ban would have effectively eliminated the problem of vertical market
power. The Commission and the Department continue to believe that a ban would
be in the best interest of Maine's consumers. We recognize, however, that the
balance arrived at in the statute remains untested, and do not here advocate any
fundamental change. Rather, we recommend limited modifications to tighten and
enhance the effectiveness of the code of conduct and market share limitation.
-10-
B. Horizontal Market Power: New England
Horizontal market power is the ability of a single dominant firm or group
of firms to profit by raising prices above competitive levels. An indicator of
the extent to which a market is subject to horizontal market power is the size
of individual market shares, and the overall level of market concentration.
Southern and central Maine form part of a regional New England wholesale
electricity market, whose geographic boundaries are coextensive with the NEPOOL
grid. Occasionally, smaller geographic markets, known as load pockets, may arise
within the grid as a result of transmission constraints or outages. Northern
Maine, a separate market, is analysed in a subsequent section of this report.
We use the Herfindahl-Hirschman Index (HHI) to estimate the level of
concentration in New England electricity markets. The HHI is an indicator rather
than an absolute measure of horizontal market power. Accordingly, we also review
additional factors in our assessment. Specifically, we look at the
responsiveness of the New England market to competitive forces, and the effect
of new entry. The related tasks of estimating levels of concentration and
analysing market power are complicated by the rapid pace of change in the New
England electric industry in recent years.
The HHI for New England's wholesale energy market for summer 2000, allowing
for new entry and out-of-region imports, shows a moderate level of concentration
by federal standards, indicating a corresponding degree of market power. With
two participants holding 50% of the market, and four over 60%, the market is
subject to oligopoly control.
Computer simulations suggest that oligopoly control may pose a special
danger in the context of New England's electricity spot market, which will
function as the principal price-setting mechanism in the region. The market may
be vulnerable to unilateral strategic behavior, or gaming, as well as collusive
practices. Simulation results show that if market leaders engage in such
manipulative behavior, wholesale clearing prices could rise by as much as an
average of 10%.
Over the next decade, planned new entry is likely to increase competition
in the New England market. In the short to medium term, market power is likely
to remain problematic. However, New England's interstate wholesale markets are
subject to federal jurisdiction. Maine's ability to address horizontal market
power in this context through legislation is limited to the margin. We recommend
a limited legislative measure focused on market power within a load pocket,
i.e., an area within Maine temporarily isolated from the grid (and federal
jurisdiction) by a transmission outage. Beyond this, the Commission and the
Department have been, and will continue to be, active in representing the
State's interest in promoting competitive regional markets before FERC.
-11-
C. Horizontal Market Power: Northern Maine
Northern Maine (Aroostook and parts of Penobscot and Washington Counties)
is isolated from the New England grid, and functions electrically as part of the
Canadian Maritime control area. It constitutes a separate geographic market for
purposes of market power analysis.
The northern Maine wholesale energy market is highly concentrated, and
subject to a corresponding degree of market power. The market is dominated by
New Brunswick Power Corporation ("NBP"), which controls transmission access to
northern Maine. NBP transmission is unsupervised by any regulatory authority,
and NBP has set discriminatory rates, with the result that it has preferential
access to the market. This transmission regime effectively excludes Hydro-Quebec
from the market, as well as participants from New England and Nova Scotia.
In addition, there exists a transmission constraint which prevents firm
power from flowing to northern Maine from New England. Moreover, the problem of
market power is probably aggravated by the lack of access to a well-designed
spot market. Finally, the prospect that new entry will increase competition in
northern Maine is minimal.
Under these circumstances, the question whether retail choice in northern
Maine should be postponed must be confronted. However, postponement should be
a last resort. Other, less drastic remedies, which offer some promise of
success, should be implemented in the first instance.
It now appears that the south-to-north constraint can be effectively
eliminated by means of a contractual arrangement whereby NBP would supply
back-up power and needed ancillary services to the four northern Maine t&d
companies. NBP has stated its willingness to enter into such undertakings with
the t&ds for a five-year term. We recommend legislation authorizing
northern Maine t&ds to contract with NBP, and empowering the Commission to
require that the purchased services be passed through to retail marketers at
cost.
NBP and provincial New Brunswick authorities indicate that the current
transmission regime is likely to be subjected to a legislative overhaul prior
to the inauguration of retail choice in northern Maine. However, the timing of
New Brunswick's restructuring remains uncertain. In the interim, it has been
proposed that, as with the tie-line interruption and ancillary services, NBP
should enter into contracts with northern Maine t&d companies to supply
transmission services. It would be preferable if these services were supplied
at NBP's lower "out" rate, rather than its higher "through" rate. Again,
legislation is recommended. A meeting among the Commission, the Department, NBP
and other parties has been scheduled to discuss these issues and arrangements.
The possible creation of a bulk power system administrator ("BPSA"), with
or without a spot market, is also under discussion among the Commission, the
Department and stakeholders. No consensus yet exists with regard to a workable
concept in this area. Accordingly, legislation would be premature. The
Commission and the Department will continue to monitor the development of a
BPSA, and may offer additional recommendations later.
-12-
While transmission enhancements do not appear to be immediately essential
to the competitive health of the northern Maine market, such enhancements would
certainly be in the long-term interest of northern Maine consumers. The
Commission and the Department will continue to monitor projects currently under
study, will keep the Legislature informed, and may offer legislative
recommendations in due course.
Finally, we recommend that, in view of the high level of market power in
northern Maine, and the uncertain efficacy of available remedies, the Commission
should be legislatively empowered to impose wholesale rate regulation to the
full extent of the State's jurisdiction. We believe that the State possesses
jurisdiction to regulate wholesale rates charged in northern Maine by generators
located in Canada. Such regulatory power should be used only as a last resort
to protect against market power, short of suspending retail choice. Even if
never used, this option could provide a useful deterrent to market power abuse.
D. Market Power in Renewables
Maine's restructuring statute requires energy marketers to demonstrate, as
a condition of licensing, that at least 30% of their supply portfolio for sales
in Maine consists of renewable resources (as defined in the statute). This
so-called Renewable Portfolio Standard ("RPS") creates a product market distinct
from generic energy. Two geographic markets are analysed here for the presence
of market power in renewables: New England and northern Maine.
The northern Maine market is highly concentrated; the New England market
moderately so. In each case, a current condition of oversupply operates to
negate market power. However, there is a potential for increased demand for
renewables in the region, and the current oversupply may prove transitory.
If the supply picture tightens, market power could become problematic in
both markets. The principal threat is that of vertical retail exclusion:
participants holding high market shares in renewables would become the
gatekeepers to Maine's retail energy markets, selecting or vetoing their retail
competitors, and determining the prices at which they could compete. This threat
is accentuated by a lack of flexible mechanisms for trading renewables, such as
tradable credits, or a power exchange.
We recommend that the Commission be legislatively empowered to suspend or
reduce the RPS in any section of the State on market power grounds.
-13-
III. VERTICAL MARKET POWER ISSUES
A. Summary
Vertical market power may be brought to bear in the electric power industry
when a utility operates a monopoly interstate transmission system and also
engages in business as a generator of energy (transmission-derived vertical
market power); or when a local transmission and distribution company (t&d) is
also a retail marketer of energy (distribution-related vertical market power).
Such an integrated enterprise can exercise vertical market power in two
principal ways: by affording preferential treatment to the competitive
affiliate; and by shifting costs to the regulated entity. Vertical market power
threatens the ultimate success of restructuring efforts by raising the barriers
to entering newly competitive markets.
Maine has addressed transmission-derived vertical market power in the
restructuring statute by requiring utilities to divest generation assets,
thereby severing the link between generation and transmission. However, New
England's electric grid spans six states, and its wholesale markets are
therefore subject to federal jurisdiction. Although some voluntary divestitures
have occurred, no other state in the region has mandated divestiture.
Accordingly, Maine must to a large extent rely on federal remedies to combat
vertical market power in these markets. The FERC has implemented open access
transmission rules, and has approved the establishment of an independent system
operator (ISO) to operate the New England grid. The Commission and the
Department are actively engaged in proceedings at FERC in which vertical market
power issues have arisen.
In contrast, Maine possesses plenary legislative jurisdiction to address
distribution-related vertical market power, which affects retail markets. In the
restructuring statute, the Legislature adopted a dual approach, enacting a code
of conduct to police the relationship between the t&d and its marketing
affiliate, and a provision limiting the market share attainable by the affiliate
in the t&d service territory. This solution represented a compromise between the
contending positions of the utilities, which opposed the market share limitation
and aspects of the code of conduct, and the Commission, which advocated a
complete ban on affiliate marketing in the t&d service territory.
A ban would have effectively eliminated the problem of vertical market
power. The Commission and the Department continue to believe that a ban would
be in the best interest of Maine's consumers. We recognize, however, that the
balance arrived at in the statute remains untested, and do not here advocate any
fundamental change. Rather, we recommend limited modifications to tighten and
enhance the effectiveness of the code of conduct and market share limitation.
-14-
B. Introduction
When an enterprise is active at more than one level of production, it is
said to be vertically integrated. Vertical integration is often accompanied by
gains in economic efficiency. The integrated firm can reduce transaction costs
and supply or input costs, and realize economies of scale and scope, enabling
it to offer lower prices to customers. Where the firm already faces healthy
competition in both vertically-related markets in which it is active therefore,
vertical integration is likely to have a beneficial, procompetitive effect.
In other circumstances, however, vertical integration can give rise to
vertical market power, conferring an ability to exact supracompetitive prices
or profits. In particular, vertical market power can be brought to bear when an
enterprise combines a regulated monopoly activity at one level of production
with a competitive activity at another level. In the electric power industry,
this situation may occur when (a) a utility operates a monopoly interstate
transmission system and also engages in the business of generation and wholesale
marketing of energy; or (b) a local transmission and distribution (t&d) company
is also a retail marketer of energy. 9
Vertical integration of a regulated transmission or distribution monopoly
with a competitive marketer may enable the integrated enterprise to exercise
market power in two ways: first, by affording the competitive affiliate
preferential treatment; and second, by shifting costs from the competitive
affiliate to the regulated entity.10 Examples of such conduct range from
blatant to subtle, and include, without limitation:
- tying purchases of competitive and regulated products
9 Another instance of vertical market power in electricity arises from the
conglomeration of a gas pipeline or coal production enterprise with electric
generation facilities. For a discussion of vertical market power generally, see
R. Binz & M. Frankena, Addressing Market Power: The Next Step In Electric
Restructuring (1998) ("Binz & Frankena") at 27 -34.
10 This analysis relies in part on the work of S. Morse & D. Howarth, MRW &
Associates, reflected in their report, Vertical Market Power Issues and Electric
Restructuring in Maine, July 31, 1998, compiled at the request of the Commission
and the Department.
-15-
- provision of discriminatory prices or discounts to the affiliate
- according the affiliate preferential access to transmission or
distribution facilities
- provision of lower quality or slower services to the affiliate's
competitors
- sharing personnel, equipment and assets between regulated entity and
affiliate at below market rates
- providing the affiliate preferential access to information
- using the regulated name and logo to benefit the affiliate
- understating the price of goods and services supplied to the affiliate
- inflating the price of goods and services supplied by the affiliate
- cross subsidies from regulated entity to affiliate. 11
To the extent that the affiliate is permitted to benefit from preferential
treatment, rivals can be disadvantaged, or even as a practical matter excluded.
To the extent that a vertically integrated enterprise can successfully shift
costs to the regulated entity, its affiliate may be enabled to compete unfairly
on price at the expense of more efficient rivals. These affiliate abuses distort
the competitive market, and could have the effect of enabling a less efficient,
higher cost supplier to achieve dominance. 12 For customers, the result is
higher prices on both counts: higher regulated prices as a result of improper
cost allocation, and higher prices in the competitive market as a result of
discriminatory practices, increased concentration and decreased competition.
In retail markets newly opened to competition, vertical market power has
a further dimension. The affiliates of vertically integrated incumbent utilities
are likely to enjoy additional significant advantages which could discourage
competitive entry by other firms. Regardless of
11 The risk of cross-subsidization is to some degree reduced, though not
eliminated, by performance-based regulation.
12 Comment of the Staff of the Bureau of Economics of the Federal Trade
Commission, May 29, 1998 ("FTC Maine Comment"), Maine PUC Docket No. 97 -877,
12.
-16-
name and logo use, the utility affiliate is likely to benefit, perhaps
substantially, from goodwill developed over the years by the incumbent utility,
as well as from customer inertia. The affiliate will also derive significant
benefit from the free transfer of valuable employee expertise from the
utility. 13
In the aggregate, these manifestations of vertical market power constitute
a formidable disincentive to entry by firms seeking to compete with the
unregulated affiliate. If prospective retail competitors perceive that the
utility affiliate can seize the lion's share of the market on the basis of
incumbent advantages and abusive practices, they may well decline to enter the
market at all. This risk may be especially serious in Maine, a small, largely
rural state which offers only a modest return to prospective entrants. Vertical
market power constitutes a significant threat to the success of Maine's
restructuring efforts.
C. Vertical Market Power In Practice
Vertical market power is more than a theoretical construct. The historical
record clearly demonstrates that vertically integrated enterprises possessing
market power have used it to their advantage, often in spite of codes of conduct
designed to prevent such abuses.
Vertical market power was the crux of the historic monopolization case
brought by the U.S. Department of Justice ("DOJ") against AT&T. In that case,
which resulted in a settlement under which AT&T was required to divest its local
exchange operations, DOJ alleged that AT&T had inflated prices paid by regulated
local telephone companies to competitive affiliates, engaged in
cross-subsidization, and discriminated against competitors. Today, as it seeks
to reenter local telephone markets, AT&T is itself the victim of alleged
preferential practices engaged in by its
13 Competitors, on the other hand, would expect to pay finding or headhunting
fees to recruit comparable expertise.
-17-
divested offspring. 14 In at least some cases, those incumbent local companies,
despite federal requirements that they open their markets to competition,
apparently have persisted in obstructing equal access to computer facilities
essential to the ability of AT&T and other competitors to enter local telephone
markets. 15
In another instance drawn from the telecommunications industry, a 1990 FCC
audit found that an unregulated NYNEX affiliate had inflated prices paid by the
regulated entity for telephone equipment, resulting in overcharges totaling
$118.5 million over a four-year period (1984 -88). Of this sum, $33.5 million
had been passed on to customers under the FCC's interstate jurisdiction.
The agency was able to secure a consent decree requiring NYNEX to refund this
amount, and to pay a $1.4 million penalty. Years later, in 1997, the New York
Public Service Commission ("NYPSC") finally concluded a long-running proceeding
focused on the same transactions with an order requiring NYNEX to refund $53
million plus interest to New York customers. This order also found that NYNEX
had underpriced subscriber lists provided to an unregulated affiliate, and
required a further $30 million refund and other relief in that regard. 16
14 E.g., Implementation of the Local Competition Provisions in the
Telecommunications Act of 1996, Petition for Expedited Rulemaking by LCI
International Telecom Corp. and Competitive Telecommunications Association, FCC
Docket No. 96-98, dated May 30, 1997, 32-38 (discriminatory processing and
support of orders by Ameritech). That AT&T may now have become the victim of its
offspring is a graphic illustration of the fact that the size of the would-be
entrant does not guarantee entry. Even Goliath can be deterred from entry where
David possesses vertical market power.
15 Known as operations support systems ("OSS"), these computer facilities are
a key element which allow for preordering, ordering, provisioning and many other
service functions, including maintenance and repair, billing, network control
and forecasting. As a bottleneck facility essential to entry into the market,
the OSS may be analogized to electric transmission or distribution systems.
Local incumbents are required to open their markets to competition under section
251 (c) of the Telecommunications Act of 1996, 47 U.S.C. sections 151 et seq.
Their alleged reluctance to comply is described in Implementation of the Local
Competition Provisions in the Telecommunications Act of 1996, Petition for
Expedited Rulemaking by LCI International Telecom Corp. and Competitive
Telecommunications Association, FCC Docket No. 96-98, dated May 30, 1997. Under
an order issued by the Federal Communications Commission ("FCC"), local
incumbents are now required to provide competitors with access to their OSS
equal to that which they afford to themselves. First Report & Order, FCC
Docket No. 96-98 (Implementation of the Local Competition Provisions of the
Telecommunications Act of 1996) (noting "anecdotal evidence suggesting that
incumbent LECs may not be providing nondiscriminatory access to OSS functions
. . . consistent with statutory requirements").
16 Binz & Frankena, App. B, 86.
-18-
There is also a history of vertical market power abuse in the electric
industry, beginning with the classic bottleneck case, Otter Tail Power Company
v. U.S. 411 U.S. 910 (1973). In Otter Tail, a vertically integrated utility's
outright refusal to wheel competing power to a neighboring municipal system over
the utility's transmission lines was found to constitute a monopolization
offense under section 2 of the Sherman Act.
Typically, however, affiliate abuses are more subtle, and less amenable to
antitrust enforcement, than an outright denial of access to the market. 17 A
marathon California case provides one example. In 1990 the California Public
Utilities Commission ("CPUC") disallowed $37.5 million in overpayments made by
SoCal Edison ("SCE") to an unregulated "qualifying facility" affiliate during
the 1980s, ruling that SCE had paid for firm capacity, while receiving only
as-available capacity. The California Attorney General commented: "The fact that
this proceeding took two years to get to an ALJ decision illustrates the limits
of regulation in detecting and correcting abusive self-dealing practices." 18
But the 1990 proceeding proved to be only the tip of the iceberg. In 1993,
the CPUC rolled the 1990 disallowance into a global settlement with SCE
amounting to $250 million, a sum characterized by the agency as "at the low end
of reasonableness," resolving years of litigation stemming from charges that SCE
had engaged in self-dealing in connection with the regulated utility's purchases
of power from a total of thirteen unregulated affiliate qualifying facility
generators. 19
17 Not all denials of access are actionable under the antitrust laws. See R.
Bolze & J. Ostoyich, Open Access & the Sherman Act: A Guide to the Essential
Facilities Doctrine, CCH Power & Telecom Law, Sep. -Oct. 1998, 10, 15.
18 73 Op. Att'y Gen. Cal. 366, 1991-1 Trade Cas. paragraph 69,427
19 Binz & Frankena, App. B, 86 -88.
-19-
Nor is the record purely historical. Allegations in recent cases, some
proven or admitted, others pending, testify to the current persistence and
intractability of vertical market power abuses. In California, an audit
performed for the CPUC Office of Ratepayer Advocates reported in 1997 that
Pacific Gas & Electric Company ("PG&E"), an incumbent utility with a regulated
t&d monopoly, applied $33.7 million of ratepayers' money to subsidize
competitive affiliates. In their 1000-page report, the auditors found a catalog
of vertical abuses, including overbilling of the regulated t&d by an affiliate
and underbilling and provision of free information by the t&d to other
affiliates. The auditors concluded that a "significant percentage of PG&E's
costs attributable to non-utility affiliates was funded by PG&E's ratepayers."
20
In Massachusetts, Boston Edison Company is alleged to have misappropriated
cost advantages and investment belonging to ratepayers in funding unregulated
subsidiaries; 21 while in Connecticut, a Department of Public Utility Control
audit uncovered attempts by Northeast Utilities to recover from monopoly
ratepayers marketing and other expenses incurred by a competitive affiliate.
22 Meanwhile, at FERC, Washington Water Power Company was recently found to
have favored its affiliate, Avista, by providing discounted transmission service
unavailable to others, in violation of open access rules. 23
A recent complaint to the New York Public Service Commission with regard
to joint marketing illustrates utility confidence that trading on incumbent
goodwill works to affiliates'
20 Overland Consulting, Audit of Affiliate Transactions of the Pacific Gas &
Electric Company (Redacted), (Oct. 1997), Executive Summary at 2; see San Jose
Mercury News, Dec. 4, 1997. In a recent telephone conversation with the
Department, the California Office of Ratepayer Advocates indicated that hearing
in this case has been completed; briefing is ongoing, and a decision is expected
within a few months.
21 DPU/DTE Order No. 97 -63, April 17, 1998 at 58; Affidavit of Gary C.
Harpster, February 24, 1998.
22 Department of Public Utility Control, Financial & Operations Review of the
Connecticut Light & Power Company, Docket No. 97 -05, Dec. 31, 1997 at 30 -31.
23 Washington Water Power Co., 83 FERC paragraph 61282 (1998).
-20-
advantage. In an October 9, 1997 advertisement in the Wall Street Journal and
the New York Times, Con Edison proclaimed:
With so many unfamiliar names out there, it's nice to know
that one thing stays the same. Con Ed Solutions and Con Ed
Development will still offer the unrivaled reliability of Con
Edison itself. After 117 years of energizing New York, we bring
proof, not promises, to the table. CON EDISON: THE COMPANY
YOU KNOW. THE PEOPLE YOU TRUST. 24
On June 26, 1998, PECO Energy was found to have violated applicable
affiliate rules by maintaining a cyberlink between its own internet page and
that of its marketing affiliate, Excelon, creating an environment which blurred
the distinction between the companies, and channeled retail customers to the
affiliate. PECO admitted the violation, commenting that "it was an oversight on
our part." 25
The pattern of affiliate abuse apparent in these cases reflects a simple
fact: management has an obligation to shareholders to explore every lawful
avenue in search of the market advantages and profits which can be gleaned from
vertical integration. It must be expected that corporate management will seek
creatively and conscientiously to discharge that obligation.
D. Transmission-Derived Vertical Market Power
Vertical market power in the electric industry may derive from integrated
ownership of (a) generation and interstate transmission facilities; or (b) a
retail marketing business and local transmission and distribution (t&d)
facilities. In this section, we consider the former.
24 See Letter, H. Fromer et al. to NYPSC Chair J. O'Mara dated Oct. 20, 1997.
25 Pennsylvania Commission Orders PECO to Remove Links on Web to Unregulated
Affiliates, Electric Utility Week's Energy Services and Telecom Report, July 16,
1998; Electric Power Alert, July 15, 1998.
-21-
Maine has sought to address vertical market power derived from transmission
ownership in part through legislation requiring incumbent utilities to divest
most generation assets. This divestiture process is already well under way. 26
If the wholesale market were geographically limited to Maine, divestiture, which
severs the vertical link between transmission and generation, would have
constituted a complete and effective remedy. 27
However, because the wholesale market of which Maine 28 forms a part
stretches across the six New England states, transmission-derived vertical
market power is a regional problem, subject to federal jurisdiction. At the
federal level, the Federal Energy Regulatory Commission ("FERC") has prohibited
discriminatory and exclusionary transmission practices through its Open Access
Rules. 29 Further, FERC has strongly encouraged the formation of Independent
System Operators ("ISO"). ISOs are special-purpose entities to which utilities
delegate control over pricing, scheduling, operation, maintenance and expansion
of a regional transmission system. With the active support of the Commission,
the New England Power Pool ("NEPOOL") (the regional utilities consortium)
proposed and FERC in June 1997 approved the establishment of ISO-New England,
Inc. ("ISO-NE"), a regional ISO for New England. 30
26 All three of Maine's investor-owned utilities are in the process of divesting
generation assets. As we note below, CMP's pending divestiture to FPL Group has
recently become the subject of litigation.
27 The remedy would be equally effective and complete, of course, if every other
state in the region mandated divestiture. However, although some divestiture has
occurred (in Massachusetts, Boston Edison Company and New England Electric
System have both sold substantial generation assets), no other state in the
region has required it. Indeed, we are not aware of any state in the country
other than Maine which has mandated divestiture through legislation. Some states
have provided incentives for voluntary divestitures.
28 Excluding a tricounty section of northern Maine.
29 Orders 888 & 889 mandate that public utilities unbundle generation and
transmission and provide the same types of transmission service to others as
they use themselves, with comparable terms, conditions, information and prices
for all.
30 New England Power Pool, 79 FERC para. 61,374 (1997). The FTC has expressed
the view that states involved in the formation of ISOs should exercise vigilance
to ensure that the ISO remains sufficiently independent. Comment of the Staff
of the Bureau of Economics of the Federal Trade Commission, May 15, 1998, La.
PSC
Continued on next page...
-22-
The principal risk from transmission-derived vertical market power is that
vertically-integrated transmission owners will discriminate against new entrants
to wholesale markets and seek to raise the barriers to entry, stifling
competition. FERC's reliance on open access rules and ISOs to protect against
this risk has not been uniformly successful. Open access behavioral rules have
not been fully effective to prevent discriminatory conduct by transmission
owners. 31 Moreover, in July 1998, NEPOOL petitioned FERC for approval of a
complex system for interconnecting newly constructed merchant plants to the grid
which assigned steep charges for unneeded transmission upgrades to new entrants.
32
The interconnection system reflected in the NEPOOL proposal constituted an
attempted exercise of vertical market power which would have raised significant
barriers to entry in New
Continued from previous page...
Docket No. U-21453, 33. The Department and the Commission will continue to
encourage ISO-NE to chart a course independent of NEPOOL. For the longer term,
some commentators predict that ISOs will turn out to be "a transitional device,
a stop on the way to a 'TransCo' or 'Gridco,' where not only operation but
ownership of transmission is divorced from generation and marketing activities."
F. Norton & G. Bernstein, ISOs -- In Search of Competitive Electricity Markets,
CCH Power & Telecom Law, Nov. -Dec. 1997, 18, 23. Others strongly advocate fully
independent transmission networks. H. Trebing, Market Concentration and the
Sustainability of Market Power In Public Utility Industries, Quarterly Bulletin
Vol. 19 No. 1, 66; R. Pierce, The Advantages of Deintegrating the Electricity
Industry, Electricity Journal, Nov. 1994, 16.
31 E.g., Petition for a Rulemaking on Electric Power Industry Structure and
Commercial Practices and Motion to Clarify or Reconsider Certain Open Access
Commercial Practices, dated March 25, 1998, FERC Docket No. 95 -8 -000, at 2.
See also Illinois Power to Recompute ATC, Wheeling & Transmission Monthly,
June 1998 (FERC has directed Illinois Power to recompute available alternative
transmission capacity following a complaint by Morgan Stanley that Illinois
Power was discriminating in favor of its own bulk power marketing arm at Morgan
Stanley's expense); and see Professor Tells FERC ATC Posting Is Bunk,
Restructuring Today, Sept. 25, 1998 (quoting R. Pierce, "if I have the means to
benefit myself and hurt a competitor I'm always going to do it").
32 The NEPOOL proposal required that every generator connected to the grid have
access to an unconstrained transmission path to any other point on the grid,
assuming that all other generation was in operation. Because planned new entry
is likely to result in a power surplus in New England, this system would
have resulted in an overbuilding of transmission, raising unnecessary barriers
to entry. Moreover, by assigning a disproportionate share of the cost of
upgrades to new entrants, NEPOOL would have accorded preferential rights to
existing transmission to incumbents.
-23-
England, and was therefore a matter of significant concern to the Department and
the Commission. 33 However, FERC has recently rejected NEPOOL's proposed
system, requiring it to formulate a new interconnection plan. 34 When a revised
NEPOOL proposal is forthcoming, it will merit careful scrutiny to ensure fair
treatment of new entrants. Accordingly, the Department and the Commission will
continue to exercise vigilance in the context of ongoing proceedings at FERC,
while working with ISO-NE and NEPOOL to achieve consensus wherever possible.
E. Distribution-Derived Vertical Market Power
In contrast to interstate transmission facilities and the regional
wholesale market, the relationship of local t&d companies to their retail
marketing affiliates is squarely within Maine's legislative jurisdiction. In its
restructuring statute, Maine has enacted a package of remedies designed to
address this aspect of the problem of vertical market power. The statute adopts
a two-pronged strategy, comprising first, a code of conduct designed to police
the relationship between t&ds and marketing affiliates, and second, an
innovative provision setting an upper limit on the market share which may be
attained by the affiliate in the t&d service territory.
1. Statutory code of conduct. The statutory code, 35 as developed in
the Commission's proposed rule,36 governs and restricts the conduct of t&d
companies and their affiliated retail marketers in the following areas.
33 See Comments of the Maine Attorney General On the NEPOOL Report of
Compliance, August 10, 1998, FERC Docket No. ER98-3853-000; Comments of the
Maine Public Utilities Commission, ISO-NE's Assessment of the Competition &
Efficiency of the NEPOOL Markets, October 13, 1998, in FERC Docket Nos.
OA97-237-000, ER97-1079-000, ER97-3574-000, OA97-608-000, ER97-4421-000 &
ER98-499-000..
34 New England Power Pool, FERC Docket No. ER98-3853-000, Draft Order
Conditionally Accepting Compliance Filing, As Modified, And Accepting, In Part,
And Rejecting, In Part, Proposed Tariff Changes, As Modified. This decision and
a companion decision has led FPL Group to file litigation in which FPL seeks
to escape from its contract to purchase CMP generation assets.
35 35-A M.R.S.A. section 3205(3).
36 The rule is authorized under 35-A M.R.S.A. sections 3205(4) (large utilities,
viz., CMP and BHE) and 3206 (2) (small utilities, viz., MPS), and applies the
same provisions to both categories.
-24-
- Favoritism. A t&d may not accord to its affiliate preferential access to
regulated products or services, or information.
- Tying. A t&d may not condition the provision of a regulated product or
service on the purchase of products or services furnished by an
affiliate.
- Information restrictions. A t&d may not share with any retail marketer
(including its affiliate) market information acquired from other
marketers or developed by the t&d in the course of providing service; or
proprietary customer information without the authorization of the
customer.
- Representations. A t&d may not: give the appearance of speaking on behalf
of an affiliate; represent that any advantage in terms of t&d service
accrues to customers of the affiliate; engage in joint marketing with the
affiliate or permit affiliate use of the t&d name and logo; provide any
opinion concerning the relative merits of competing retail marketers.
- Separation. T&d employees may not be shared with and must be physically
separated from those of an affiliate (separate buildings,
telecommunications and computer systems); records and books of account
must be separately maintained.
- Penalties. The code provides for two levels of sanctions for violations.
Any violation may be punished with an administrative penalty in the
amount of $10,000 per day; knowing violations which result or have the
potential to result in substantial injury to consumers or competition may
be penalized with an order requiring the t&d to divest its retail
affiliate.
Numerous states have adopted or are considering codes of conduct. Measured
against provisions in place in other jurisdictions, the code reflected in
Maine's statute and proposed rule represents a comprehensive effort to address
the problem of vertical market power. 37 Nevertheless, as we discuss below,
there are limited areas in which the statutory code should be tightened and
improved.
2. Statutory market share limitation. The second prong of the
statutory strategy for dealing with vertical market power is the market share
limitation. 38 This provision
37 Among states which have adopted or are considering codes of conduct governing
retail marketing of electricity by t&d affiliates are California, Illinois,
Massachusetts, Oregon and Texas. A number of other states have in place rules
governing affiliate marketing of gas (Delaware, Georgia, Indiana, Kansas,
Maryland, Missouri, New Jersey, New Mexico, New York, Ohio, Rhode Island,
Pennsylvania and Wisconsin).
38 35-A M.R.S.A. section 3205 (2) (B).
-25-
limits the retail affiliate of a t&d to an overall 33% market share within the
service territory of the t&d. In addition, a limit of 20% is imposed on the
share of standard offer (default service) business which may be awarded to the
affiliate in the t&d service territory. The market share limitation applies to
Central Maine Power ("CMP") and Bangor Hydro-Electric Company ("BHE"), but does
not apply to Maine Public Service Company ("MPS"), the sole "small utility"
within the statute.
The purpose of the market share limitation is twofold: to prevent a t&d
affiliate from actually amassing a dominant market share within its service
territory, and to ensure that its perceived ability to exert dominance does not
chill potential new entry. No other state has enacted or adopted a market share
limitation. 39
3. Legislative compromise. Maine's two-pronged statutory approach was
developed as a compromise between contending opposites. Utilities strongly
disagreed with the market share limitation, and took issue with aspects of the
code of conduct as well. In particular, the joint marketing ban, interpreted in
the proposed Commission rule as a bar on use of the same name and logo by the
t&d and its marketing affiliate, has been controversial.
On the other hand, the Commission and the Department continue to subscribe
to the view that a structural solution, i.e., enactment of a complete or partial
ban on retail marketing by affiliates in the t&d territory, would have been
preferable to the regulatory approach selected by the Legislature. 40
Nevertheless, we recognize that experience may be the best guide to whether the
rules established by the statute should be relaxed or reinforced. We therefore
recommend only
39 However, the California Public Utilities Commission ("CPUC") has considered
and rejected a similar measure. Opinion Adopting Standards of Conduct Governing
Relationships Between Utilities and Their Affiliates, CPUC Decision 97 -12 -088,
Dec. 16, 1998, Conlon, Comm'r, dissenting, 4 (hereinafter "Conlon, dissenting").
Conlon proposed a market share limitation fixed at 20% of each market segment
(industrial, commercial, residential). It would have remained in effect for two
years.
40 A partial ban would apply to the competitive retail market, but not the
standard offer bid process.
-26-
relatively minor (though in our view important) proposed enhancements to the
statutory code and market share limitation provisions.
In the paragraphs following, we review (a) the importance of retaining the
ban on shared name and logo use; (b) recommended code enhancements; (c) the
value of the market share limitation, and recommended modifications; and (d) the
merits of a prophylactic ban as a residual option.
4. The name & logo issue. Maine's statutory code bars joint
advertising or marketing by the incumbent utility and its marketing affiliate.41
In its proposed rule, the Commission has interpreted this prohibition to include
use of the same or a substantially similar name or logo. 42 Discussing the
proposed rule in a recent decision, the Commission held that the name
"MainePower" is not substantially similar to "Central Maine Power," and
authorized its use. The Commission noted that while the rule bans joint
advertising or marketing, CMP and MainePower may nevertheless disclose their
affiliation in response to inquiry, or in nonmarketing contexts such as
shareholder communications or regulatory filings. 43
Other states have addressed the joint marketing issue in various ways.
California, for example, rejected a prohibition on shared name and logo use,
requiring instead an accompanying affirmative disclosure that the affiliate is
a separate, nonregulated entity, and that the customer does not have to purchase
the affiliate's product in order to continue to receive regulated service from
the t&d. 44 However, a recent scholarly analysis concludes that a ban on joint
use of an
41 35-A M.R.S.A. s. 3205 (3) (J).
42 Rule para. 3 (J) (2).
43 Order dated July 6, 1998, Maine PUC Docket No. 97 -930.
44 California Affiliate Transaction Rules, para. V.F. Texas and Massachusetts
are considering similar rules. Such provisions may not always have the desired
effect. Shortly before the inauguration of retail competition in California,
PG&E ran a nationwide ad campaign in which the required disclaimer was virtually
illegible due
Continued on next page...
-27-
incumbent brand is warranted, at least during the initial development phase of
a newly deregulated market. 45
There are compelling reasons for retaining the prohibition on shared name
and logo use without modification. As long as the utility and its marketing
affiliate share the same name and logo, it will be difficult to dissociate the
two entities in the marketplace or for purposes of regulation. As a result, to
permit shared name and logo use would represent an open invitation to the
incumbent utility (a) to engage in cross-subsidization (promoting its name at
ratepayer expense for the benefit of the unregulated affiliate); 46 (b) to
capitalize on the familiarity of its name to seize a high market share in the
initial phase of market development, discouraging entry by others; 47 and (c)
to deceive consumers by suggesting that affiliation with the t&d results in
greater quality or reliability of service. 48
5. Code enhancements. Maine's code is reasonably comprehensive, but
should be improved and tightened by means of legislation in limited areas.
Continued from previous page...
to small font size, dark background and its placement on the vertical margin.
The CPUC immediately determined that a violation had occurred; it has since
levied a $1.68 million penalty. CPUC Fines PG&E For Misuse Of Name And Logo In
Promotions By Electricity Affiliate, November 5, 1998, http://www.cpuc.ca.
gov/news/981105_PG&E_Fined.htm.
45 J. Abel & M. Clements, Should Utility Incumbents Be Able To Extend Their
Brand Name to Competitive Retail Markets? An Economic Perspective, Electricity
Journal, June 1998, 49, 56 (hereinafter "Abel & Clements") ("allowing
unrestricted brand name extension from an incumbent utility to an affiliate in
the emerging competitive retail market could seriously cripple viable market
entry and, therefore, the early phases of retail competition").
46 See Comment of the Staff of the Bureau of Economics of the Federal Trade
Commission, June 19, 1998 Before the Public Utilities Commission of Texas,
Project No. 17549, 4 -5 ("FTC Texas Comment") ("a regulated parent utility may
have an incentive to overinvest in reputation building" if it is able to include
investments in its reputation in its rate base while realizing gains in the
unregulated market; "[h]arm to both competition and consumers may occur from
overinvestment and cross-subsidization").
47 Abel & Clements 56; Conlon, dissenting, 3.
48 Binz & Frankena 71; FTC Texas Comment 5 (if substantial minority of consumers
takes a particular message from advertisement, and that message is likely to
mislead consumers to their detriment, advertisement is deceptive under Federal
Trade Commission Act s. 5; affiliate use of incumbent name and logo may violate
this standard, if it implies to consumers "that the relationship between the
utility and the affiliate is different from what it really is").
-28-
- Cross-subsidization. No provision of the current statutory code directly
addresses the problem of cross-subsidization. Cross-subsidization is
addressed in the proposed rule by means of a provision to the effect that
"[a] distribution utility and its affiliated competitive provider must
comply with all applicable provisions of Chapter 820", a reference to the
Commission's so-called Cochrane rule, which is authorized by 35-A M.R.S.A
sections 713 -715. Nevertheless, because it is an expression of vertical
market power which could damage competition, cross-subsidization should be
explicitly prohibited and penalized in the statutory code of conduct. 49
- Log. The code currently requires the t&d to maintain a log of all
requests for information made by the marketing affiliate and its
competitors. 50 As an aid to detection and enforcement, the Commission
should be empowered to extend this requirement to other categories of
transactions by rule.
- Penalties. The statutory code provides for two types of sanctions, as
noted above. The divestiture remedy for knowing violations substantially
injurious to consumers or competition is a draconian measure valuable as
a deterrent, but likely to be employed only as a last resort. The only
other option available is a financial penalty of up to $10,000 per day for
any code violation. 51 However, it is possible to conceive of one-time
violations, for example an advertising violation or an exchange of
information, serious enough to render a $10,000 penalty entirely
inadequate. 52 In order to give the rule additional force as a deterrent,
and to afford the Commission more flexibility in crafting appropriate
remedies, provision should be made for an intermediate penalty, e.g.,
suspension of the right to engage in retail marketing for up to three
years, and a much more substantial maximum financial penalty for certain
one-time offenses (up to $100,000). In addition, disgorgement of profits
or benefits should be available as a sanction. Finally, the statute should
be amended to make clear that the penalty provisions of the code of conduct
are applicable to small t&ds (i.e. MPS) as well as large ones.
6. Market share limitation issue. Foreclosing shared name and logo use
reduces, but does not eliminate, the risk of market dominance. We anticipate
that by March 1,
49 It is far from clear that a violation of the Cochrane rule would be subject
to the sanctions provided in the code of conduct section of the restructuring
statute, including divestiture, unless that section is amended.
50 35-A M.R.S.A. s. 3205 (3) (H).
51 35-A M.R.S.A. s. 3205 (5).
52 The CPUC recently fined PG&E $1.68 million for an advertising violation. See
fn. 35 above.
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2000, the implementation date for retail choice, many consumers in the CMP
service territory will know that MainePower is a CMP affiliate. 53
In markets where an incumbent utility has long held a monopoly, incumbent
goodwill and customer inertia can exert a powerful drag on competition. For
example, in 1984, the year of its breakup, AT&T was able to retain a 90% share
of the long-distance market. It took a dozen years before that share dropped
below 50%.54 Absent a market share limitation, it could well "take years [for
incumbent market shares] to decline to where there would be general agreement
that market dominance was not a problem." 55
The market share limitation serves an important purpose -- that of
permitting "entry of enough additional marketers to ensure a competitive
market." 56 Its removal would therefore be ill-advised, unless affiliate
marketing in the t&d territory is banned altogether. Rather, it represents an
essential element of the balance struck by the Legislature in Maine's
restructuring statute. However, we recommend that the Commission's ability to
penalize violations of the market share limitation be enhanced and clarified.
The statutory penalty provisions may be inadequate to remedy violations of
the market share limitation. As written, it is not clear whether the penalty
provision, 35-A M.R.S.A. s.
53 In recent press releases, CMP draws attention to its affiliation with
MainePower. E/PRO Wins Contract for Edwards Dam Removal, Sept. 15, 1998
(MainePower listed as a subsidiary in article unrelated to its activities);
Clarifying CTP Stock Listing, CMP Group, Sept. 3, 1998 (MainePower listed as
subsidiary in article relating to listing of parent company stock). Further, a
visit to CMP's webpage readily yields information concerning "MainePower, a unit
preparing to operate as a competitive electricity marketer." www.cmpco.com.
54 It is sobering to note that in California's retail electric market, only
33,000 of 10 million retail customers initially chose an alternative provider,
despite an $89 million consumer education campaign.
55 K. Costello & K. Rose, Some Fundamental Questions on Market Power: No Easy
Answers for State Utility Regulators, Electricity Journal, July 1998, 73. See
also W. Shepherd, Monopoly and Antitrust Policies In Network-Based Markets Such
as Electricity, 14 (Paper delivered at Symposium on Virtual Utility, Rensselaer
Polytechnic Institute, March 31, 1996) (dominance and tight oligopoly usually
fade slowly, if at all).
56 Conlon, dissenting 4.
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3205 (5), would cap penalties for market share limitation violations at $10,000
- -- surely an inadequate sanction. The statute should be amended to provide for
greater flexibility, and a much more significant maximum penalty. Disgorgement
of profits for minor infractions, and surrender of revenues for more serious
breaches, should be provided as options. 57
7. Ban on marketing by affiliates. In the restructuring statute, the
Legislature has chosen a regulatory or behavioral approach to address the
problem of vertical market power, combining a code of conduct and a market share
limitation. In making this policy choice, the Legislature rejected an
alternative, structural remedy, namely, enactment of a complete ban on marketing
by t&d affiliates.58 Maine's selection of a regulatory rather than a structural
remedy is consistent with restructuring policies adopted across the country.
While numerous states have enacted or promulgated codes of conduct, to our
knowledge no state has imposed a ban on marketing by affiliates. Two states,
California and New Hampshire, have explicitly considered and rejected such a
ban. 59
We are not here advocating that the untested compromise approach reflected
in the statute be abrogated. Even if it is not ideal from our perspective, it
may prove a workable solution.
57 Note that the statute requires the Commission to reevaluate the need for the
market share limitation, and report on its findings to the Legislature, no later
than January 1, 2005. 35-A M.R.S.A. s. 32121 (2).
58 The Commission recommended a ban on affiliate marketing in its Restructuring
Plan. See Final Restructuring Plan, December 1, 1996, 32. This recommendation
was discussed further in a letter from the Commission to the Chairs of the Joint
Standing Committee on Utilities & Energy dated April 28, 1997.
59 In California, The Utility Reform Network (TURN) moved for a two-year ban on
affiliate marketing. In denying the motion in favor of a code of conduct
approach, the CPUC explained its view that dominance by an affiliate marketer
was less likely because California's implementation of retail choice did not
involve a phase-in. Opinion Adopting Standards of Conduct Governing
Relationships Between Utilities and Their Affiliates, CPUC Decision No. 97 -12
- -088, Dec. 16, 1998, 15 -17. In New Hampshire, the Public Utilities Commission
initially approved a restructuring plan which included a ban on affiliate
marketing in the t&d service territory. In Re Restructuring New Hampshire's
Electric Utility Industry, 175 PUR4th 193, 222 (1997). Subsequently, the PUC
vacated this prohibition, deferring a final determination on the issue until a
later time. Electric Utility Restructuring, Order On Requests for Rehearing,
Reconsideration and Clarification, Order No. 22,875 (NH PUC, Mar. 20, 1998), 23.
For a discussion of this issue, see K. Jaffe, Emerging State Rules For Retail
Marketing By Electric Utilities After Restructuring, CCH Power & Telecom Law,
May-June 1998, 34, 35 -36.
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However, a ban on affiliate marketing in the t&d service territory remains an
important residual option, should experience show that permitting any marketing
by t&d affiliates is inimical to the public interest. Accordingly, we review the
merits of a ban below.
Enactment of a ban would not be unprecedented. To cite one important
analogy, local Bell telephone monopolies are barred by law from providing long
distance service within their regions until they show that they have opened
their local networks to competition. 60 Moreover, there is a
compelling logic to the structural approach: a ban would constitute a totally
effective solution which would eliminate, once and for all, the problem of
vertical market power. It would appear that even if it proves workable, the
regulatory solution selected in Maine necessarily falls short, measured against
this standard.
It is a consistent theme of both the U.S. Department of Justice ("DOJ") and
the Federal Trade Commission ("FTC") (in contrast to the states) that structural
remedies for market power are invariably more effective than behavioral
monitoring and enforcement. The reasons for this conviction are well stated by
William Baer, FTC Bureau of Competition Director, in a recent speech:
A behavioral approach ... has several drawbacks. First,
it does not eliminate the incentive and opportunity to
engage in exclusionary behavior. Rules can try to limit
the opportunity, but few rules are invulnerable to evasion.
Second, detection of violations can be very difficult. For
example, discrimination in access could take the form of
a subtle reduction in the quality of service, whose effects
60 47 U.S.C. s.271 (a) & (b). Significantly, these provisions were recently
upheld over a constitutional challenge. SBC Communications, Inc. v. FCC, No. 98
- -10140, September 4, 1998 (5th Cir.); may be found at
http://www.ca5.uscourts.gov/opinions/pub/98/98-10140-CV0.HTM. See also
Commonwealth Edison Company v. Illinois Commerce Commission, 692 N.E.2d 1350
(Ill. App. 1998) (upholding regulatory agency's denial of utility petition for
approval to provide energy support services to energy users).
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could be difficult to identify and measure. Third, behavioral
rules can require long-term monitoring of compliance,
which can be a costly process .... Fourth, it may be difficult
to know whether we have selected the right rules.61
There are two other important reasons for rejecting the regulatory,
behavioral approach to vertical market power. The first is that restructuring
should be conceived as far as possible as a process of deregulation: opening
markets to unfettered competition, for the benefit of consumers. Reregulation
designed to accommodate the participation of t&d affiliates in retail markets
is inconsistent with the fundamental goals of restructuring, and appears
calculated to benefit t&d shareholders rather than consumers. A second reason
is that, just as there is a need for a regional ISO to be an independent grid
administrator, so it is essential that the t&d responsible for local
distribution of electricity be neutral and independent. Permitting a t&d
affiliate to engage in retail marketing runs the risk of compromising its
neutrality.
Experience underscores the limitations of the regulatory approach. 62 In
the course of the AT&T divestiture litigation, officials of the Federal
Communications Commission ("FCC") testified to the ineffectiveness of regulation
in preventing vertical market power abuses. In advocating divestiture rather
than a court-ordered code of conduct, DOJ made clear its view that "[n]either
of these problems [favoritism and cross-subsidization] has thus far proven
amenable to
61 W. Baer, FTC Perspectives on Competition Policy & Enforcement Initiatives in
Electric Power, Washington D.C. Dec. 4, 1997.; see J. Klein, Making the
Transition From Regulation To Competition: Thinking About Merger Policy During
the Process of Electric Power Restructuring, Washington DC, Jan. 21, 1998 ("the
regulatory agency often ends up playing catch-up, while the market forces move
forward and the underlying competitive problems escape real detection and
remediation").
62 Most of the examples of vertical market power in action cited above occurred
in spite of regulatory code of conduct provisions.
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successful regulatory solution .... [T]he anticompetitive problems inherent in
the joint provision of regulated monopoly and competitive services are ...
insoluble." 63 In approving the proposed settlement, the court agreed:
AT&T's pattern during the last thirty years has been to
shift from one anticompetitive action to another, as
various alternatives were foreclosed through the action
of regulators or the courts or as a result of technological
development. In view of this background, it is unlikely
that, realistically, any injunction [i.e. code of conduct]
could be crafted that would be both sufficiently detailed
to ban specific anticompetitive conduct yet sufficiently
broad to prevent the various conceivable kinds of anti-competitive
conduct that AT&T might employ in the future.
Thus, the court preferred the "surer, cleaner remedy" of divestiture adopted in
the proposed settlement. 64
A ban on affiliate marketing represents a readily attainable and fully
effective solution to the problem of vertical market power. 65 Experience of
the regulatory approach in other jurisdictions suggests that, by contrast (1)
it does not prevent the exercise of vertical market power; (2) detection,
prosecution and proof of violations can be difficult, uncertain, costly and
time-consuming; and (3) successful abuses can net very substantial gains to the
utility at consumer expense. In addition, it requires little insight to predict
that for every meritorious allegation of a regulatory violation, there will be
numerous groundless complaints which must nevertheless be investigated and in
some cases litigated. 66 Ultimately, the high cost of regulation and its
apparent
63 DOJ, Response to Public Comments on the Proposed Modification of Final
Judgment, 47 Fed. Reg. 23, 320 -336 (1982).
64 U.S. v. AT&T, 552 F.Supp. 131, 167, 168 fn. 155 (D.DC 1982).
65 There are less draconian options which could be considered. A partial ban on
affiliate marketing, in the competitive segment of the market only, would leave
the affiliate free to compete for standard offer business.
66 For example, in the event of another ice storm, it is easy to imagine an
avalanche of complaints with regard to any t&d affiliate customer who happened
to be reconnected before any customer of another competitive provider.
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inability to solve the problem of market power could jeopardize the success of
the fundamental goals of restructuring: open and robust competition, and lower
prices.
Accordingly, if the legislative compromise reflected in the statute proves
unworkable, the Commission and the Department respectfully counsel that a ban
on affiliate marketing in the t&d territory should be reconsidered. 67
F. Costs of Regulation
Precision in estimating the costs of regulating affiliate marketing is
elusive. However, the costs of regulation may be high.
The purpose of regulation is to protect the retail market from the damage
to competition which could be wrought by the exercise of vertical market power.
The need for regulation arises from the participation of the t&d affiliate in
the retail market. The motive for such participation, of course, is profit.
Regulation, then, is a necessary condition of the t&d affiliate's license to
profit from energy sales in the retail market. It can be argued, on this basis,
that all the costs of such regulation should be borne by affiliate marketers and
their stockholders.
Under the present legislative scheme, however, it appears that the costs
of the regulatory effort required to police the vertical boundary between the
t&d and its affiliate will be borne entirely by ratepayers.68 At a minimum, we
recommend legislation to adjust this burden by
67 Note that it can be plausibly argued (although we are not necessarily
persuaded) that allowing the participation of t&d marketing affiliates benefits
consumers by increasing consumer choice. It can also be argued (and we are
persuaded) that t&d affiliates should be given the opportunity to demonstrate
that they can play by the rules.
68 The restructuring statute requires the Commission to report to the
Legislature annually regarding its "actual and estimated future costs of
enforcing and implementing the provision of this chapter governing the
relationship between a [t&d] utility and an affiliated competitive electricity
provider and the costs incurred by [t&d] utilities in complying with those
provisions." 35-A M.R.S.A. s. 3217 (1). At the outset, however, the
Commission's costs appear to be chargeable to its general budget funded by
utility assessments, and ultimately to ratepayers.
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imposing the cost of meritorious enforcement proceedings under the code of
conduct or market share limitation on shareholders rather than ratepayers.
G. Recommendations
1. There is a need for an enhanced statutory penalty provision for
exceeding market share limitations.
2. The statutory code of conduct should be tightened as follows:
(a) Cross-subsidization should be explicitly prohibited.
(b) The Commission should be empowered to expand the requirement
that a log of information requests be maintained to include other
categories of transactions.
(c) More flexible provision for penalties should be made in order to
enhance deterrence and enforcement. This should include provision for
intermediate penalties for code infractions, e.g., a three-year maximum
license suspension, and a $100,000 maximum for certain one-time violations;
and provision for disgorgement of profits.
3. It should be provided that all costs of enforcement which result from
violations of the code of conduct and the market share limitation may be
assessed against the t&d and its affiliate.
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IV. HORIZONTAL MARKET POWER: NEW ENGLAND
A. Summary
Horizontal market power is the ability of a single dominant firm or group
of firms to profit by raising prices above competitive levels. An indicator of
the extent to which a market is subject to horizontal market power is the size
of individual market shares, and the overall level of market concentration.
Southern and central Maine form part of a regional New England wholesale
electricity market, whose geographic boundaries are coextensive with the NEPOOL
grid. Occasionally, smaller geographic markets, known as load pockets, may
arise within the grid as a result of transmission constraints or outages.
Northern Maine, a separate market, is analysed in a subsequent section of this
report.
We use the Herfindahl-Hirschman Index (HHI) to estimate the level of
concentration in New England electricity markets. The HHI is an indicator rather
than an absolute measure of horizontal market power. Accordingly, we also review
additional factors in our assessment. Specifically, we look at the
responsiveness of the New England market to competitive forces, and the effect
of new entry. The related tasks of estimating levels of concentration and
analysing market power are complicated by the rapid pace of change in the New
England electric industry in recent years.
The HHI for New England's wholesale energy market for summer 2000, allowing
for new entry and out-of-region imports, shows a moderate level of concentration
by federal standards, indicating a corresponding degree of market power. With
two participants holding 50% of the market, and four over 60%, the market is
subject to oligopoly control.
Computer simulations suggest that oligopoly control may pose a special
danger in the context of New England's electricity spot market, which will
function as the principal price-setting mechanism in the region. The market may
be vulnerable to unilateral strategic behavior, or gaming, as well as collusive
practices. Simulation results show that if market leaders engage in such
manipulative behavior, wholesale clearing prices could rise by as much as
an average of 10%.
Over the next decade, planned new entry is likely to increase competition
in the New England market. In the short to medium term, market power is likely
to remain problematic. However, New England's interstate wholesale markets are
subject to federal jurisdiction. Maine's ability to address horizontal market
power in this context through legislation is limited to the margin. We recommend
a limited legislative measure focused on market power within a load pocket,
i.e., an area within Maine temporarily isolated from the grid (and federal
jurisdiction) by a transmission outage. Beyond this, the Commission and the
Department have been, and will continue to be, active in representing the
State's interest in promoting competitive regional markets before FERC.
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B. Introduction
Horizontal market power is the ability of a single dominant firm or group
of dominant firms to profit by raising prices above competitive levels. As
single firm market shares increase, and the number of competing firms declines,
markets become more vulnerable to market power. As an initial matter,
therefore, the extent to which a market is subject to horizontal market power
can be gauged by reference to the market shares of individual firms, as well as
overall market concentration.
An assessment of market concentration in wholesale electricity must begin
by defining the market in terms of products and geography.
C. Product Markets
The most important product for analysis in this report is electric energy.
The most straightforward measure of market share for this product is capacity,
which is currently traded separately. In addition to energy and capacity,
competitive wholesale markets in New England will also trade in ancillary
services. 69 Further, there may be circumstances in which it is useful to
consider energy generated in a particular period, e.g., peaking energy, as a
distinct product. 70 Similarly, energy required at a particular time, in a
particular quantity, such as Maine's standard offer service, which will go out
to bid pursuant to the restructuring statute in the summer of 1999, may merit
consideration as a separate product market.
69 Ancillary services include Ten-Minute Spinning Reserve ("TMSR"); Ten-Minute
Nonspinning Reserve ("TMNS"); Thirty-Minute Operating Reserve ("TMOR"); Operable
Capability; and Automatic Generation Control ("AGC"), also known as load
following.
70 This is because electricity demand cannot easily be shifted from one period
to another; nor can electricity be stored easily in large quantities.
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Usually, however, because of the interplay among these markets, energy is
likely to serve as a good proxy for other electricity products in the context
of a competitive assessment. 71 In this section, accordingly, the primary focus
is the electric energy product market. At the same time, we attempt to assess
whether market power problems peculiar to any related product market may
give special grounds for concern. 72
D. Geographic Markets
In the electric power industry, the geographic market depends on the
configuration of the grid. The extent to which power can be transmitted from
point to point free of constraints or bottlenecks, which could interfere with
open competition, defines the boundaries of the market. In most hours, under
normal operating conditions, transmission is relatively unconstrained throughout
the NEPOOL grid, which covers all of the six New England states except northern
Maine (a tricounty area comprising Aroostook and parts of Penobscot and
Washington Counties). Accordingly, it seems fair to accept, as a working
hypothesis, that in most hours, southern and central Maine (i.e., all sections
except the tricounty area) form a part of a regional New England wholesale
electricity market. 73
However, in a small number of hours, southern and central Maine may
experience a peak load which exceeds the capacity of transmission ties to import
competing supplies from
71 Joint Application Under Section 203 of the Federal Power Act For the Sale and
Purchase of Generation Facilities and Related Properties, On Behalf of CMP et
al., FPL et al.; Testimony and Workpapers of Joe D. Pace ("Pace") 13 -14
(natural interplay between energy and reserve and load following markets; and
between capacity and operable capability markets).
72 Maine's restructuring statute requires that, as a condition of licensing,
competitive electricity providers demonstrate that no less than 30% of their
portfolio of supply sources for retail electricity sales in the State are
accounted for by renewable resources as defined in the statute. This requirement
results in the creation of a separate product market, which is the subject of
a subsequent section of this report. 35-A M.R.S.A. s. 3210.
73 New England Power Pool, FERC Docket Nos. OA97-237-000, ER97-1079-000, NEPOOL
Market Power Analysis, Feb. 28, 1997, Prepared Direct Testimony of William H.
Hieronymus ("Hieronymus") 19 (principal relevant geographic market is NEPOOL
region); New England Power Co., FERC Docket Nos. ER-98-6-000, EC-98-1-000,
Market Power Analysis: Affidavit & Workpapers of Dr. Joe D. Pace, e.g. at
paragraph 34 (to same effect).
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out-of-state. Under these circumstances, southern and central Maine would become
a "load pocket." Within the load pocket, some generation facilities would be
required to run in some hours in order to meet demand. 74 The owners of these
"must-run" facilities would possess market power in affected peak hours. In
addition, temporary load pockets may arise from time to time in unusual
conditions 75 in more narrowly defined sections of the State. Finally, load
pockets may also arise in some circumstances as a result of strategic or
manipulative actions by market participants. 76
E. Concentration Analysis
1. Herfindahl-Hirschman Index. Federal and state antitrust agencies
(including the Department) employ the Herfindahl-Hirschman Index (HHI) to
measure market concentration. 77 The HHI is arrived at by adding the squared
market shares of all the competitors in a given market. This simple mathematical
device expresses the insight that market power increases exponentially in
proportion to market share. Federal antitrust guidelines used by the
Department in merger enforcement indicate that a market with an HHI of 1000 or
less should be viewed as unconcentrated (and therefore likely to function
competitively). 78 A market with an
74 Hieronymus 23 (Maine experiences transmission constraints in less than 0.5%
of hours); CMP Request for Approval of Sale of Generation Assets, February 20,
1998, Maine PUC Docket No. 98-058, Prefiled Testimony and Exhibits of David M.
Conroy, 5-6 (must-run generation may operate for periods of limited duration if
outage occurs).
75 E.g., transmission outages caused by meteorological events, such as ice
storms.
76 Hieronymus 25 (entity with considerable share of generation within a
potentially constrainable interface could increase bid substantially, causing
ISO to dispatch enough out-of-area generation to exhaust transmission capacity).
We have not determined whether such manipulative actions could be brought to
bear in any section of Maine.
77 Horizontal Merger Guidelines, 57 Fed. Reg. 41552 (1992) ("Guidelines")
paragraph 1.5.
78 Id. paragraph 1.51 (a). For example, ten firms with market shares of 10% each
would yield an HHI of 1000 (10 squared x 10).
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HHI between 1000 and 1800 is described as moderately concentrated; while any HHI
over 1800 is termed highly concentrated. 79 Federal authorities consider that
a merger increasing the HHI by more than 100 points to a total in the 1000 to
1800 range "potentially raise[s] significant competitive concerns." 80 It is
presumed that a merger which elevates the HHI by 100 or more points to a
postacquisition total exceeding 1800 is "likely to create or enhance market
power or facilitate its exercise." 81 A market in the moderately to highly
concentrated range may therefore be viewed as likely to be subject to an
increasingly significant degree of market power.
The theoretical basis for using an HHI calculation to judge the level of
competition likely to be found in a market is long experience indicating that
a high level of concentration tends to facilitate collusive and other
anticompetitive behavior. Oligopolies (such as price cartels) are most
effective when there are few members. When there are many sellers, and no
dominant ones, vigorous price competition is more likely to emerge. The HHI
analysis is an attempt to measure and predict the level of concentration at
which oligopolistic behavior contrary to consumer interest is likely to occur.
2. NEPOOL grid. The NEPOOL grid represents a distinct electrical
control area, i.e., an integrated electrical system with centralized dispatch.
It is interconnected to the west with the New York Power Pool ("NYPP"), to the
northwest with the Hydro Quebec system ("HQ"), and to the northeast with New
Brunswick Power Corporation ("NBP"). Like other control areas in North America,
the NEPOOL grid initially developed as a patchwork of isolated, vertically
integrated utility systems, each generating and distributing to customers in a
discrete
79 A market comprising five firms with market shares of 20% each would result
in an HHI of 2000 (20 squared x 5).
80 For example, an acquisition of a competitor with a 2% market share by a rival
with a 25% share would increase the HHI by 100 points. Any merger where
(acquired share) x (acquirer share) x 2 = 100 would have the same effect.
81 Guidelines paragraph 1.51 (c)
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service territory. The grid took shape as regional connections were forged to
enhance reliability and economy of service. The NEPOOL consortium, formed in
1971 in response to a massive electrical blackout affecting the entire
northeast, was conceived as a means of more effectively assuring reliability and
economy through coordinated operation. The consortium is made up of a
large number of disparate public and investor owned utilities, and other
generators.
3. A moving target. Over the past two years, NEPOOL has undergone a
period of rapid evolution in preparation for the inauguration of competitive
wholesale and, eventually, retail markets. As a means of addressing vertical
market power concerns, FERC has authorized the transfer of control of NEPOOL
transmission facilities to an independent system operator, ISO New England, Inc.
("ISO-NE"). 82 ISO-NE now handles dispatch, and administers NEPOOL's open
access transmission system. Once FERC authorization is received, it will also
operate competitive auction markets. When implementation of these markets is
authorized, dispatch will shift from a cost-based to a bid-based system. 83
Moreover, several important investor owned utilities in the region have
taken steps to divest generation facilities. In particular, New England Electric
System ("NEES"), a large Massachusetts-based utility, has completed the sale of
all of its nonnuclear generation assets to USGen New England, Inc. ("USGen"),
a subsidiary of PG&E; while Boston Edison Co. ("BECO") has divested substantial
assets to Sithe Energies, Inc. ("Sithe"). Central Maine Power's ("CMP")
proposed sale of generation to FPL Group ("FPL") and Bangor Hydro-Electric's
("BHE") proposed divestiture to PP&L are currently pending. Most recently, the
giant Connecticut-based Northeast Utilities ("NU") has announced its intent to
divest generation assets.
82 New England Power Pool, 79 FERC paragraph 61,374 (1997).
83 NEPOOL and ISO-NE have petitioned FERC for market implementation as of
December 1, 1998.
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In some cases, these divestitures, to the extent they are approved and
consummated, may significantly affect concentration and competition in New
England electricity markets.
At the same time, technological advances which have reduced the size and
cost of gas-fired generation, together with the expected arrival of natural gas
through a pipeline from Nova Scotia, have prompted an unprecedented level of
interest in the construction of new generation capacity, in many cases by new
entrants to the market. To the extent that it is realized, such new entry would
also have significant positive implications for concentration and competition
in New England.
Yet another factor which can have a significant influence on levels of
concentration is the extent to which utilities retain obligations to serve
"native load" pursuant to regulatory requirements 84 , as a result of
contractual buybacks following divestiture, 85 or as default provider after
the inauguration of retail choice. 86 If a utility's capacity is committed
to serving native load, it is obviously unavailable to other customers in
competitive markets. In Maine, native load obligations will cease to exist
concurrently with the inauguration of retail choice on March 1, 2000. It is
reasonable to assume that in due time, native load obligations will disappear
throughout the region. However, they will disappear on different, and in many
cases, unknown schedules in different jurisdictions. This complicates the task
of assessing regional concentration levels at particular points in time.
These issues are described in greater detail below. We allude to them here
for the purpose of pointing out that in light of the rapid evolution of the New
England market, the task of
84 Most U.S. jurisdictions still require utilities to provide retail services
in a specific franchise territory. As restructuring moves ahead, these native
load obligations will disappear.
85 For example, USGen has entered open-ended buyback contracts with NEES.
86 In some jurisdictions, the utility remains the default provider after the
inauguration of retail choice.
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assessing levels of concentration and their competitive implications becomes a
highly contingent and problematic exercise.
4. New England HHI. In focusing the HHI lens on the New England
market, we have reviewed studies prepared by Bruce Biewald and Timothy Woolf of
Synapse Energy Economics, Inc., as well as the workpapers of experts retained
over the past two years variously by NEPOOL, USGen, CMP and FPL. Figure 1 below,
which depicts an HHI for the New England market for summer 2000, is based on
Synapse's work, with limited adjustments. 87 This analysis reflects the
following assumptions:
- all proposed NEES, CMP and BECO divestitures are consummated and approved
- no NU divestitures are consummated or approved
- no utility retains an obligation to serve native load
- 50% of announced new entry scheduled for service by summer 2000 actually
occurs 88
- 1800 mw of HQ imports are allocated to parties currently receiving them
under contract 89
- moderate NYPP imports (500 mw) are included
- NBP imports are capped at tie capacity (700 mw).
To the extent that the above assumptions turn out to be invalid, major
adjustments in the estimated HHI may prove warranted. For example, if NU were
to move forward with significant piecemeal divestitures of its generation
assets, the HHI could decline markedly. Conversely, the HHI would increase
somewhat if less than the assumed amount of new entry actually occurred.
87 Synapse examines several scenarios with regard to new entry; we employ a
relatively conservative assumption in this regard (including 50% of new entry
scheduled to be in service by summer 2000). In addition, we include NYPP
imports at 500 mw and NBP imports at 700 mw.
88 It is unlikely that sufficient gas will be available to support more than 50%
of announced new entry.
89 As of 2001, as a result of contract expirations, HQ will be free to enter the
market in its own right.
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Figure 1: Summer 2000 New England HHI
Gen. Mw % HHI
BECO 1363 5 25
BHE 249 1 1
CMP 522 2 4
Commonw. 502 2 4
Eastern Util. 518 2 4
FPL 1080 4 16
NBP 700 3 9
NEES 555 2 4
NU 8465 32 1024
Sithe 1983 7 49
Southern Co. 820 3 9
USGen 5119 19 361
Utd. Illum. 1484 6 36
Vt. Group 1181 4 16
Other 2245 8 10
TOTAL 26786 1572
The total HHI of 1572 places the New England market in the moderately
concentrated range, suggesting that there are correspondingly significant
grounds for concern with regard to market power as the process of restructuring
moves forward.
5. Standard offer HHI. With the beginning of retail access, the
Commission is charged with the responsibility of ensuring the availability of
standard offer service for customers who prefer not to select their own
competitive provider. Pursuant to the restructuring statute, prior to July 1,
1999, the Commission must devise and complete a bid process to select providers
for each t&d service territory. 90 The operative date on which the
selected standard offer providers would commence service is the date set for
implementation of retail choice, viz., March 1, 2000. Thus, in addition to
assessing general levels of concentration in the New England market, there is
a specific need for assurance that the market will be configured in such a way
as to support a competitive bid process conducted in the summer of 1999, for
90 35-A M.R.S.A. s. 3212.
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delivery of a significant quantity of power (Commission staff estimates a
maximum of 1400 mw), beginning March 1, 2000. Again, Figure 2 below, with minor
adjustments, is based on Synapse's analysis. In an effort to arrive at an
estimate of the minimum level of competition likely to obtain in this market,
we adopt the following conservative assumptions:
- providers must be able to offer a minimum of 100 mw
- all utilities in the region outside Maine are subject to 100% native load
obligations
- no scheduled new entry participates 91
- no NYPP imports are included
- NBP's market share is capped at 700 mw to reflect intertie capacity. 92
Figure 2: Standard Offer HHI
Gen. Mw % HHI
BHE 249 7 49
CMP 522 16 256
FPL 1064 32 1024
Great Bay 141 4 16
Milford Pwr 149 4 16
NBP 700 21 441
NU 507 15 225
TOTAL 3332 2027
In this instance, the HHI point total indicates a highly concentrated
market. The significance of this figure, however, must be evaluated in light
of the purpose of the assessment in this instance: to gauge the level of
competition for purposes of a one-time bid process rather than an ongoing
market.
The market is configured in a way that may facilitate market power in a bid
process. Relatively few players may be able to vie for a significant portion
of the State's standard offer
91 Although four new facilities with total capacity in excess of 1000 mw are
scheduled to come on line by the end of 1999, we prefer to assume that none of
them will be ready to participate in a bid process by the summer of 1999.
92 NBP has expressed interest in participating in the standard offer bid
process.
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business. Furthermore, we have not yet collected available information
concerning the production costs of available capacity. This level of
competition, therefore, may not be sufficient to enable the Commission to meet
the statutory goal of selecting at least three providers of standard offer
service for each service territory, without an adverse impact on consumer
prices. 93 Of course, the statute permits the Commission to select only one
provider in any given territory, if this result will best serve consumer
interests. Even so, there is some degree of uncertainty as to whether
competition will be adequate to assure a healthy outcome.
Accordingly, the standard offer bid process will bear close watching.
Careful reassessment of available uncommitted capacity in the spring of 1999,
with attention to its production costs, would be advisable. 94 At this time,
however, legislative action does not appear to be warranted. The Commission
retains the ability to advise the Legislature of any needed corrective action
after the results of the bid are in, pursuant to the statute. 95
6. Ancillary services HHIs. We have not engaged in an independent
assessment of levels of concentration in New England markets for ancillary
services. However, we have reviewed the HHI analyses of these markets put
forward variously by Dr. William Hieronymus (on behalf of NEPOOL) and Dr. Joe
Pace (on behalf of CMP and FPL). The differing results arrived at by these
experts are compared in Figure 3 below. The markets analysed include
Ten-Minute Spinning Reserve ("TMSR"); Ten-Minute Nonspinning Reserve ("TMNS");
Thirty-Minute Operating Reserve ("TMOR"); Operable Capability; and Automatic
Generation Control ("AGC"), also known as load following.
93 35-A M.R.S.A. s. 3212.
94 We have not as yet developed the information necessary to review the
estimated production costs of the uncommitted capacity which we expect to be
available to compete for Maine's standard offer service.
95 35-A M.R.S.A. sections 3212, 3217.
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Figure 3: New England Ancillary Services HHIs
Hieronymus (1999) Pace (2000)
TMSR 872 2676
TMNS 928 2217
TMOR 1010 1907
Op. Cap. 843 1483
AGC 1447 1962
At first glance, the obvious discrepancy between these results might appear
problematic, particularly since Pace's HHIs almost uniformly suggest that
ancillary services markets are subject to a high degree of market power.
Moreover, an examination of the underlying figures reveals some apparent
disagreement between the two experts concerning the precise amounts of capacity
likely to be available in New England to provide these services. However, the
primary reason why Hieronymus' results are in every case sharply lower than
Pace's is methodological. Hieronymus followed a practice of truncating market
shares by capping them at the total amount of estimated demand in the relevant
market, while Pace did not. As Hieronymus argues:
Given [a] pattern of excess supply, the true competitiveness
of the market is better reflected by a concentration measure
that does not artificially overstate the market share of the large
suppliers whose potential supply exceeds the total demand in
the market. This 'truncated HHI' ensures that the measure of
concentration does not reflect redundant capacity and imply
market power that does not actually exist, simply because the
HHI calculation has been performed mechanically. By truncating
the capacity of any supplier at the total market demand (and thus
calculating the truncated HHI) the measure of concentration can
be made more rational. 96
Because we agree with the truncation methodology employed by Hieronymus in this
instance, 97 we are inclined to accept his assessment to this extent: it seems
fair to conclude that the New
96 Hieronymus 29.
97 Truncation may not always be appropriate. If demand levels are fluid and
uncertain, as in the renewables market discussed below, this factor should be
referenced in the analysis, rather than incorporated into the HHI.
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England markets for ancillary services will be no less competitive, and subject
to no greater degree of market power, than the energy and capacity markets. 98
F. Market Power in New England
Our Herfindahl summary of the New England energy market arrives at an HHI
result of 1572, indicating a moderate level of concentration. Federal merger
guidelines provide that an acquisition which increases an HHI in the moderate
1000-1800 point range by an additional 100 points "potentially raises
significant competitive concerns." 99 Similarly, our New England HHI result
should be interpreted as justifying potentially significant market power
concerns.
However, "market share and concentration data provide only the starting
point" for a competitive analysis. 100 The HHI is a screening device, not an
absolute indicator of the presence or absence of market power. In this section,
therefore, we assess the importance of other factors affecting competition in
the New England market which may argue that a greater or lesser degree of market
power concern is appropriate. In particular, an analysis of the responsiveness
of the New England market to competitive forces, and the impact of anticipated
new entry, is offered in the paragraphs following.
1. Responsiveness of the market to competitive forces. Three
fundamental facts hold broad implications for the competitive success of the
regional wholesale electricity market. First, the persistence of a culture of
coordination during the transition to open markets is likely. Second, the
oligopoly structure of the New England electricity industry, as currently
configured, enhances the risk of coordination and collusion. Third, the New
England
98 Note, moreover, that Hieronymus and Pace agree that entry into ancillary
services markets is substantially easier than entry into energy and capacity
markets. Hieronymus 39; Pace 15.
99 Guidelines paragraph 1.51 (b).
100 Id. paragraph 2.0
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spot market, under proposed rules, may be susceptible to unilateral, as well as
coordinated or collusive manipulation to drive up prices. These points are
discussed briefly below.
Shaped by a century of regulation and a common commitment to system
reliability, the electric industry harbors a culture of coordination and
cooperation. In a newly competitive environment, perspectives and motivations
formed by regulation may lead to actions which are inappropriate,
anticompetitive and in some cases illegal. As FTC Chair Robert Pitofsky recently
explained to a Congressional committee:
because industry participants have become used to a
regulated environment, some may attempt to protect
or duplicate many of the comfortable aspects of that
environment. Where they are accustomed to coordinated
interaction and the use of the regulatory process to bar
or disadvantage new entry, industry members may attempt
to use monopolistic or cartel behavior to protect their
entrenched positions after deregulation. A monopolist will
not ordinarily welcome new entry, and issues of access
or structural realignment to promote access will have to
be considered .... 101
The tactics of coordination and collusion can be employed not only to bar
or disadvantage new entry, but also to exercise market power to drive wholesale
prices up. In the electric industry, the coordinated or collusive exercise of
market power is facilitated by the ready availability of historical and
(depending on market design) current data which permit market participants to
"draw accurate inferences with respect to each other's pricing strategies and
cost structures." 102
101 Prepared Statement of the Federal Trade Commission, Presented by Robert
Pitofsky, Chairman, Before the Committee on the Judiciary, U.S. House of
Representatives, June 4, 1997, http://www.ftc.gov/os/1997/9706/ electric.htm
102 R. Pierce, Antitrust Policy in the New Electric Industry (Draft Paper), 44
("Pierce").
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With two players holding an aggregate market share of 50% and four holding
well over 60%, it is clear that the New England wholesale electricity market is
characterized by oligopoly control. 103 The resulting risk of coordination and
collusion is aggravated by a pattern of joint ownership of facilities. Taking
account of this pattern of joint ownership, it has been estimated that together,
market leaders NU and USGen possess the ability to control or influence the
wholesale bids for 65% of the capacity in the market. 104
Oligopoly control poses a special danger in the context of an electricity
spot market, where daily interaction offers ample opportunities for dominant
groups to police and enforce collusive arrangements. 105 The principal
price-setting mechanism in the New England market will be the spot market be
operated by ISO-NE. An oligopolistic industry structure renders this market
vulnerable not only to coordination and collusion, but also to unilateral
"strategic behavior," or "gaming," designed to maximize profits. Such behavior
can take a variety of forms, including "economic withholding," withholding
capacity within a constrainable interface, and more complicated strategies, as
briefly outlined below.
Under proposed rules, sellers will bid power into the spot market
twenty-four hours in advance for each hour of the succeeding day. Currently, no
mechanism exists for buyers to place demand-side bids. 106 The market will
clear for each hour at the price bid for the last block of power required to
meet demand in that hour. All buyers will pay, and all sellers receive, the
market-clearing price. In this system, participants with high market share will
possess the ability
103 W. Shepherd, Monopoly and Antitrust Policies in Network-Based Markets Such
as Electricity, 12 (tight oligopoly exists when four firms hold more than 60%
of the market).
104 P. Cramton & R. Wilson, A Review of ISO New England's Proposed Market Rules,
September 9, 1998, 8, 23 ("Cramton & Wilson").
105 Cramton & Wilson, 39.
106 The ISO has proposed instituting a demand-side bidding mechanism; however,
the timing of this needed reform remains doubtful. See discussion below.
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to bid so high on a particular facility or block of power as to effectively
withhold its capacity from the market, thereby driving up the market-clearing
price for all power sold in that hour. This practice, referred to as "economic
withholding," could give rise to considerable price volatility. Computerized
simulation modeling performed by Synapse Energy Economics demonstrates that if
NU unilaterally engages in such economic withholding, the result would be a
significant increase in average wholesale clearing prices, perhaps by as much
as 10% on an annualized basis. Of course, all sellers would benefit, since all
receive the market-clearing price. If two or more market leaders adopted
economic withholding strategies, it is likely that sellers would collectively
secure an even greater benefit, with a correspondingly greater price impact.
107 These results indicate that in the context of the electricity spot market,
where two market leaders control an aggregate 50% of a market with a 1500-point
HHI, the market power risks are substantial.
Finally, as NEPOOL acknowledges, an entity which possesses capacity
concentrated within a potentially constrainable interface can engage in economic
withholding of capacity to create a load pocket and exercise market power within
it.108 Indeed, as a result of the strong "interaction effects" felt across
transmission grids, even more complicated strategies may be
107 B. Biewald, D. White & W. Steinhurst, Horizontal Market Power in New England
Electricity Markets: Simulation Results & a Review of NEPOOL's Analysis, June
11, 1997, 15, Table 1 (computer simulation modeling shows a 29.7% price impact
based on strategic withholding by NU; and a 32.1% price impact based on
strategic withholding by four market leaders); New England Power Pool, FERC
Docket Nos. OA97-237-000 & ER97-1079-000, Testimony of Bruce Edward Biewald on
Behalf of the Maine Attorney General, January 23, 1998 (with extreme
conservative sensitivity adjustments to the model, strategic withholding by NU
and USGen results in a 5.9% price impact); T. Woolf, B. Biewald & D. White,
Memorandum: Market Power Analysis of New England Using the ELMO Model, October
29, 1998 (based on updated market share data, modeling shows that NU economic
withholding would cause 9.6% price impact; this could be dramatically higher if
anticipated new entry fails to materialize).
108 Hieronymus, 24 -25.
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available. For example, a firm might in some circumstances be in a position to
exercise market power by increasing production for the purpose of "bottling up"
a disproportionate amount of competing generation. 109 At the present time,
we simply do not know the extent to which such Machiavellian strategies may be
available to dominant players in New England, or to which they could affect
wholesale and, ultimately, retail prices in Maine.
2. Impact of new entry. As the Federal Trade Commission correctly
emphasizes, "timely, likely and sufficient entry may alter the competitive
implications of market structure," and provide an antidote to market power.110
Certainly, it is likely that new entry in the New England generation industry
will reduce concentration over the next decade. The extent to which such new
entry will be sufficient to remedy market power on a timely basis, however,
remains in doubt. Federal guidelines consider entry sufficiently easy to
constrain the exercise of market power only if entry could be accomplished
within two years. 111
A number of factors have emerged to enhance the prospect that new entry
could occur on a significant scale in the region over the next several years.
The advent of new combined-cycle gas-turbine technology has reduced both the
cost and the time required to effect entry into generation markets. Deregulation
of natural gas prices has lowered fuel costs; and the ready
109 W. Hogan, A Market Power Model with Strategic Interaction in Electricity
Networks, Energy Journal Vol. 18 No. 4, 107 at 109 (firm could exercise market
power by increasing production to "bottle up" disproportionate amount of
competing generation), 111 (electrons choose their own path in transmission
grid, producing "strong interaction effects"), 127 (citing possibility of "cases
where with a well-placed combination of plants and constraints, a generation
company with market power could act to both raise critical prices and increase
its volume by blocking competitive production that amounts to more than its own
increase in output"), 130 (adverting to "the ability of 1 mw of incremental
generation at one location to block production of more than 1 mw elsewhere").
110 Comment of the Staff of the Bureau of Economics of the Federal Trade
Commission, May 29, 1998, Maine PUC Docket No. 97 -877 at 3.
111 Guidelines paragraph 3.2. See EPRI, Technical Assessment Guide, Vol. 1:
Electricity supply -1993 (Revision 7), June 1993, Exhibit 23 (preconstruction,
license and design time for new generation is two years; construction time is
an additional two years).
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availability of Canadian gas with the addition of pipeline capacity transiting
the region is now a near-certainty.
The result has been an explosion of enthusiasm for the construction of new
capacity. Projects totaling nearly 30,000 mw of new, largely gas-fired capacity
have been announced on varying schedules throughout the region.112 If all of
these new projects were developed, regional capacity would more than double,
resulting in a significant surplus. Much of the announced new capacity would be
constructed by new entrants. 113 Moreover, of the roughly 30,000 mw total, as
much as 10,000 mw is planned for completion within the next two years. 114 Of
this 10,000 mw regional total, it is noteworthy that approximately 2500 mw would
be built by new entrants within the State of Maine.
No one expects that all of the announced new capacity will actually be
built. The prospect of a significant surplus by itself will surely serve to
dampen the ardor of some developers and their financiers. As more new capacity
comes on line, late-starting projects will suffer an increasing rate of
attrition. 115 Moreover, it is unlikely that there would be enough gas
available to support more than half of the announced projects.
Further, the established utilities within NEPOOL have supported policies
which, whether by design or otherwise, have impeded the entry of new
competitors. In particular, NEPOOL devised an expensive and time-consuming
process for considering applications to interconnect with the existing grid, and
planned to levy substantial charges against new entrants for arguably
112 Interconnection Study Status,
http://www.iso.ne.com/transmission_services_and_generation_interconnected
/documents/New10/13/98nnections.
113 Some on the other hand, would be built by participants which already possess
significant market share, such as USGen.
114 I.e., before the end of calendar 2000.
115 W. Short, Competitive Retail Markets: Tenuous Ground for Renewable Energy
(Draft Paper 1998) 5.
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unnecessary transmission upgrades purportedly required by their projects.116
FERC has recently rejected many of these policies, requiring NEPOOL to come
forward with new interconnection proposals. 117 When revised NEPOOL proposals
are forthcoming, they will merit careful scrutiny to ensure fair treatment of
new entrants.
Despite promising signs, therefore, new entry remains something of an
imponderable. If (as we assumed for purposes of the above HHI calculations) half
of the new capacity scheduled to be in service by the end of 2000 is completed
on time, and if this success-rate is maintained in the years ahead, new entry
will exert a gradually increasing procompetitive influence in the New England
wholesale market. Moreover, if half of the new capacity planned within the State
of Maine (i.e., 1250 mw) is constructed within the next two years, the
possibility of a southern and central Maine load pocket will all but disappear.
However, our HHI and modeling results suggest that, given the current oligopoly
structure of the electricity industry in New England, new entry alone cannot be
relied upon to provide a sufficient remedy to market power in the short to
medium term.
G. Remedies for Market Power in New England
The ability of the Maine Legislature to take remedial action to protect
competition in the New England market is limited to the margin. The operation
of wholesale electric power markets in interstate commerce and the wholesale
rates which prevail in such markets are within the
116 See Comments of the Maine Attorney General On the NEPOOL Report of
Compliance, August 10, 1998, FERC Docket No. ER98-3853-000.
117 New England Power Pool, FERC Docket No. ER98-3853-000, Draft Order
Conditionally Accepting Compliance Filing, As Modified, And Accepting, In Part,
And Rejecting, In Part, Proposed Tariff Changes, As Modified, 8 (NEPOOL
evaluation criteria unrealistic and unreasonable), 9 (existing SIS procedures
cumbersome and ineffective), 11 (NEPOOL queuing process to be addressed in the
context of an upcoming filing) 13 (expansion cost pricing to be addressed in the
context of a future NEPOOL filing relating to congestion pricing). As an
intervenor in this proceeding, the Department, as well as the Maine Public
Advocate, had protested aspects of the NEPOOL compliance filing which
unnecessarily raised barriers to entry.
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exclusive jurisdiction of FERC. 118 Accordingly, in order to avail itself of
appropriate remedies to market power in the regional market, the State of Maine
must in most cases pursue and champion those remedies before FERC and, if
necessary, in the federal courts. Indeed, to a large extent, such remedies must
be sought in the context of a single ongoing proceeding, which will broadly
determine the future course of wholesale restructuring in New England. That
proceeding is NEPOOL's application to FERC for market-based rate authority, and
related dockets. 119
1. NEPOOL market-based rate application. In the context of federal
restructuring of wholesale electric power markets, FERC possesses the power to
grant or deny market participants' applications to charge market-based, as
opposed to regulated, cost-based rates. To obtain such authorization, market
participants must show that they do not possess market power in the relevant
market, or that market power has been adequately mitigated. 120
Initially filed on December 31, 1996, NEPOOL's long-running application for
market-based rate authority on behalf of its members, including NU, USGen and
others, is still pending. While arguing that none of its participants possessed
market power except to a limited extent in potential load pockets, NEPOOL in
December 1997 proposed a comprehensive market power mitigation plan ostensibly
designed to remedy precisely the type of strategic behavior modeled by Synapse.
The NEPOOL mitigation plan would empower the ISO to respond to economic
withholding tactics by various means, including imposition of default pricing
or limitations on a participant's bid flexibility. 121
118 E.g. Maine Yankee Atomic Power Company v. Public Utilities Commission, 581
A.2d 799, 804 (Me. 1990) (Commission had no authority to require reduction in
generator's wholesale rate, set exclusively by FERC; attempt to do so
preempted).
119 New England Power Pool, Market Power Analysis, February 28, 1997, FERC
Docket Nos. OA97-237-000 & ER97-1079-000.
120 E.g. New York State Gas & Electric Corporation, 78 FERC paragraph 61309 at
62326 (1997).
121 New England Power Pool, Market Monitoring, Reporting, and Market Power
Mitigation Proposal, December 19, 1997, FERC Docket Nos. OA97-237-000 &
ER97-1079-000.
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NEPOOL has also filed a regional transmission tariff and a package of
proposed market rules to govern the spot market. 122 In June, 1997, FERC
authorized the creation of ISO-NE to manage transmission and dispatch functions.
123 The ISO will also administer the spot market, when its implementation is
authorized. However, neither bid-based dispatch nor the spot market can be
implemented until FERC rules on NEPOOL's market-based rate application.
Among its other duties, ISO-NE is required to independently assess the
competitiveness of the markets it administers. 124 In a recent development,
ISO-NE in September 1998 filed a study of the competitiveness of the spot market
under NEPOOL's proposed rules. 125 The study finds that significant flaws in
the market design advanced by NEPOOL are likely to accentuate market power, and
proposes a series of wide-ranging reforms. In particular, the study recommends
installation of a multi-settlement system, a location-based pricing congestion
management system, and demand-side bidding. It also counsels abolition of
capacity trading markets, as well as significant adjustments to ancillary
services markets. While endorsing most (but not all) of the study's
recommendations, ISO-NE nevertheless advocates full implementation of
competitive wholesale markets by December 1, 1998, and apparently continues to
support a full grant of NEPOOL's application for market-based rate authority on
that schedule. 126
The Department, the Commission and the Public Advocate have all been active
as intervenors in this and related FERC dockets. While committed to the same
objective, viz., to protect and promote competition in New England electricity
markets, we have adopted somewhat
122 New England Power Pool, Restructured Arrangements, December 31, 1996, FERC
Docket Nos. OA97-237-000 & ER97-1079-000. There has been a series of supplements
to this initial filing.
123 New England Power Pool, 79 FERC paragraph 61,374 (1997).
124 Interim Independent System Operator Agreement paragraph 6.4.
125 Cramton & Wilson.
126 Motion of ISO-NE To Include Its Market Assessment In Docket and Requesting
Order Permitting Market Implementation On December 1, 1998, FERC Docket Nos.
OA97-237-000, ER97-1079-000, ER97-3574-000, OA97-608-000, ER97-4421-000 &
ER98-499-000.
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divergent positions. In general, the Department and the Public Advocate have
advocated structural remedies to market power, i.e, appropriate divestitures;
the Commission favors a regulatory approach.
More specifically, the Department and the Public Advocate oppose granting
NEPOOL or its members market-based rate authority, and oppose market
implementation, until (1) NU, USGen and perhaps Sithe divest capacity to reduce
market concentration; and (2) critical market reforms proposed by ISO-NE's
experts can be put in place. 127 The Department and the Public Advocate lack
confidence in the ISO's ability to detect and remedy the exercise of market
power under NEPOOL's proposed mitigation plan. 128
The Commission, joining with other New England commissions, through filings
by the New England Conference of Public Utilities Commissioners ("NECPUC"),
opposed NEPOOL's initial application on the ground that market power was
present, arguing that a mitigation plan was required; NECPUC then played a role
in negotiating the plan ultimately adopted and filed by NEPOOL. NECPUC now takes
the position that NEPOOL's mitigation plan is generally adequate, and supports
market implementation on the schedule proposed by ISO-NE, but asks that FERC
require adoption of the market reforms proposed by the ISO's experts by
September
127 As an alternative, the Department and Public Advocate have submitted that
FERC could grant NEPOOL's application in part, and implement markets, while
confining NU, USGen and perhaps Sithe to cost-based bids.
128 Comments of the Maine Attorney General on the NEPOOL Market Monitoring,
Reporting & Market Power Mitigation Proposal, January 23, 1998, FERC Docket Nos.
OA97-237-000 & ER97-1079-000; Comments of the Maine Attorney General on the
NEPOOL Sanctions Rule (Market Rule 13), July 17, 1998, FERC Docket No.
ER98-3568-000; Memorandum of the Maine Attorney General & the Maine Public
Advocate In Opposition to Motion of ISO-NE To Implement Markets, October 9,
1998, FERC Docket Nos. OA97-237-000, ER97-1079-000, ER97-3574-000, OA97-608-000,
ER97-4421-000 & ER98-499-000.
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1, 1999. In a separate comment, the Commission has requested that FERC
accelerate development of a congestion management system. 129
At this juncture, several options are open to FERC, ranging from a full
grant of NEPOOL's application, and unconditional implementation of the spot
market by December 1, 1998, to a denial of the ISO's implementation request, and
an order for a full hearing on NEPOOL's application. We cannot predict how FERC
will resolve these matters. However, it is certain that market power issues
will persist as wholesale restructuring moves forward. The Department and the
Commission will continue their efforts to represent the State's interest in
these proceedings.
2. Other remedies. Because of federal preemption, the State in most
cases lacks jurisdiction to legislatively address market power within a load
pocket on the New England grid. It is hoped that the likelihood that a load
pocket could arise in southern and central Maine will recede as new entrants
within Maine come on line. However, localized load pockets could arise or be
created; other strategic actions could be taken which might affect wholesale
prices within the State. The Commission and the Department intend to monitor
developments, using computerized simulation modeling where appropriate, to
ensure as far as possible that anticompetitive activity with a wholesale price
impact is detected. To the extent that such price effects are felt, it may be
that (as the Federal Trade Commission has pointed out) specific
129 Comments of NECPUC On NEPOOL Market Monitoring, Reporting & Market Power
Mitigation Proposal, December 22, 1997, FERC Docket Nos. OA97-237-000 &
ER97-1079-000; Letter, NECPUC President S. Geiger to FERC Commissioners, October
15, 1998; Answer of NECPUC In Support of Motion of ISO-NE To Include Its Market
Assessment In Docket and Requesting Order Permitting Market Implementation,
October 13, 1998; Comments of the Maine Public Utilities Commission, ISO-NE's
Assessment of the Competition & Efficiency of the NEPOOL Markets, October 13,
1998, all in FERC Docket Nos. OA97-237-000, ER97-1079-000, ER97-3574-000,
OA97-608-000, ER97-4421-000 & ER98-499-000.
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transmission enhancements or new generation projects can be proposed and
encouraged as a practical remedy. 130
However, where a load pocket arises in all hours for any significant
duration, for example as a result of a meteorological event or other emergency,
we believe that, for the period during which the connection to the regional grid
is severed, interstate commerce and federal jurisdiction are also cut off. 131
It is to be hoped, of course, that such events will be rare. However, recent
experience suggests that a month-long load pocket in an isolated section of the
State could give rise to serious (even if relatively short-lived) market power
concerns. Specifically, a situation could arise where the only generation
available within the load pocket would sell only at exorbitant rates.
Accordingly, we recommend that the Commission be empowered to assert
jurisdiction over wholesale rates on market power grounds in any section of the
State in which a load pocket arises for all hours for more than forty-eight
hours. 132
H. Recommendation
The Commission should be empowered to assert jurisdiction over wholesale
rates on market power grounds in any section of the State in which a load pocket
arises for all hours for more than forty-eight hours.
130 Comment of the Staff of the Bureau of Economics of the Federal Trade
Commission, May 29, 1998, Maine PUC Docket No. 97-877 at 8 (using computer
simulation modeling of the grid and generation, the Department and the
Commission may be able to identify a small, focused list of transmission or
generation projects which could alleviate the most significant market power
concerns).
131 See Federal Power Commission v. Florida Power & Light Co., 404 U.S. 453, 463
(1972) (jurisdiction premised on commingling of energy transmitted in interstate
commerce, as determined by engineering or scientific test). There could of
course be no such commingling when transmission lines are severed.
132 In addition, we plan further study with regard to the advisability of
legislation to provide for civil remedies for an exercise of market power in a
load pocket.
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V. HORIZONTAL MARKET POWER: NORTHERN MAINE
A. Summary
Northern Maine (Aroostook and parts of Penobscot and Washington Counties)
is isolated from the New England grid, and functions electrically as part of the
Canadian Maritime control area. It constitutes a separate geographic market for
purposes of market power analysis.
The northern Maine wholesale energy market is highly concentrated, and
subject to a corresponding degree of market power. The market is dominated by
New Brunswick Power Corporation ("NBP"), which controls transmission access to
northern Maine. NBP transmission is unsupervised by any regulatory authority,
and NBP has set discriminatory rates, with the result that it has preferential
access to the market. This transmission regime effectively excludes Hydro-Quebec
from the market, as well as participants from New England and Nova Scotia.
In addition, there exists a transmission constraint which prevents firm
power from flowing to northern Maine from New England. Moreover, the problem of
market power is probably aggravated by the lack of access to a well-designed
spot market. Finally, the prospect that new entry will increase competition in
northern Maine is minimal.
Under these circumstances, the question whether retail choice in northern
Maine should be postponed must be confronted. However, postponement should be
a last resort. Other, less drastic remedies, which offer some promise of
success, should be implemented in the first instance.
It now appears that the south-to-north constraint can be effectively
eliminated by means of a contractual arrangement whereby NBP would supply
back-up power and needed ancillary services to the four northern Maine t&d
companies. NBP has stated its willingness to enter into such undertakings with
the t&ds for a five-year term. We recommend legislation authorizing northern
Maine t&ds to contract with NBP, and empowering the Commission to require that
the purchased services be passed through to retail marketers at cost.
NBP and provincial New Brunswick authorities indicate that the current
transmission regime is likely to be subjected to a legislative overhaul prior
to the inauguration of retail choice in northern Maine. However, the timing of
New Brunswick's restructuring remains uncertain. In the interim, it has been
proposed that, as with the tie-line interruption and ancillary services, NBP
should enter into contracts with northern Maine t&d companies to supply
transmission services. It would be preferable if these services were supplied
at NBP's lower "out" rate, rather than its higher "through" rate. Again,
legislation is recommended. A meeting among the Commission, the Department, NBP
and other parties has been scheduled to discuss these issues and arrangements.
The possible creation of a bulk power system administrator ("BPSA"), with
or without a spot market, is also under discussion among the Commission, the
Department and stakeholders. No consensus yet exists with regard to a workable
concept in this area. Accordingly, legislation would be premature. The
Commission and the Department will continue to monitor the development of a
BPSA, and may offer additional recommendations later.
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While transmission enhancements do not appear to be immediately essential
to the competitive health of the northern Maine market, such enhancements would
certainly be in the long-term interest of northern Maine consumers. The
Commission and the Department will continue to monitor projects currently under
study, will keep the Legislature informed, and may offer legislative
recommendations in due course.
Finally, we recommend that, in view of the high level of market power in
northern Maine, and the uncertain efficacy of available remedies, the Commission
should be legislatively empowered to impose wholesale rate regulation to the
full extent of the State's jurisdiction. We believe that the State possesses
jurisdiction to regulate wholesale rates charged in northern Maine by generators
located in Canada. Such regulatory power should be used only as a last resort
to protect against market power, short of suspending retail choice. Even if
never used, this option could provide a useful deterrent to market power abuse.
B. The Geographic Market
Remote from the remainder of New England, northern Maine is characterized
by significant special features which demand a separate assessment of market
power in energy and ancillary services. The first task in performing such an
analysis is to define the geographic market.
The northern Maine electrical grid, which powers Aroostook as well as
portions of Penobscot and Washington Counties, is unique.133 While the remainder
of the State is fully integrated into the NEPOOL control area, this tricounty
grid functions electrically as a part of the Canadian province of New Brunswick.
Moreover, conditions in the northern Maine market contrast sharply with those
in the rest of New England. In particular:
- Northern Maine is connected only to New Brunswick; the only existing
transmission link to New England (or anywhere else) is through New
Brunswick.
- Northern Maine can draw on firm power imports only from Canada, since
under current conditions the transmission tie through New Brunswick to
New England cannot carry firm power south to north.
133 We refer to the Aroostook-Penobscot-Washington County grid below as "the
tricounty grid," "the tricounty area", or simply as "northern Maine."
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- New Brunswick, which governs much of the control area of which northern
Maine forms a part, has no current plan to develop competitive wholesale
or retail markets. 134
- New Brunswick transmission is currently governed by discriminatory
policies determined unilaterally by the utility, New Brunswick Power
Corporation ("NBP"), an instrumentality of the provincial government
which operates free of regulatory oversight by any Canadian or U.S.
agency. 135
- The Maritime control area has no ISO, and no spot market.
New England, by way of comparison, is interconnected to, and can draw on
imports of firm power from three other regions, viz., New York, Quebec and New
Brunswick. A competitive wholesale market already exists in New England; most
states in the region are moving, albeit on different schedules and with varying
policies, toward retail choice. Moreover, the NEPOOL control area is governed
by FERC's nondiscriminatory, open access transmission regime. New England
utilities have transferred control of their transmission systems to ISO-NE,
which will operate a spot market for energy and ancillary services, and will be
empowered to apply measures designed to prevent or mitigate the exercise of
market power.
Northern Maine, then, presents an electrical anomaly. Politically linked
to New England, and governed by Maine's restructuring initiative, it is
nevertheless isolated from the region by the configuration of existing
transmission ties. Electrically connected to New Brunswick, the tricounty area
is separated from the province not only by the international frontier, but by
contrasting energy policies which make a unified market impossible. There is no
escaping the
134 The provincial government, however, has initiated a policy discussion
concerning restructuring options. D. Savoie & D. Hay, Electricity in New
Brunswick and Options for its Future, July 1998 ("Savoie & Hay"),
http://www.gov.nb. ca/legis/reports/energ-98/index.htm
135 Specifically, NBP levies a rate for "through" transmission (for power
transiting the province) which is 40% higher than the "out" rate which it
charges itself. The NBP "out" rate is 60% higher than rates which apply in New
England.
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conclusion that northern Maine must be viewed as a geographic market unto
itself, separate from both New England and neighboring sections of Canada for
purposes of a market power analysis. 136
Indeed, strictly speaking, northern Maine may constitute not one but two
separate geographic markets. This is because the greater part of the territory
served by Eastern Maine Electric Cooperative is not connected to the remainder
of the tricounty grid except through New Brunswick. Because the market power
problems afflicting the two markets are identical, however, they may be treated
as one for purposes of this analysis.
C. Concentration Analysis
Having delineated the geographic contours of the northern Maine market, we
turn in this section to an assessment of the levels of concentration and
competition within it. As in the analysis of the New England market above, we
employ the Herfindahl-Hirschman Index ("HHI"), a screening device used by
federal antitrust enforcement authorities (as well as FERC) as an indicator of
market power. The HHI is the sum of the squared market share percentages of each
market participant. The next step, then, is to identify the participants, and
determine their market shares. 137 Generating capacity is used as a gauge of
the market shares in energy of in-market participants, while tie-line capacity
sets an upper limit on the market shares of importers.
In contrast to the larger new England market, which includes a large number
of entities possessing varying amounts of generation capacity, northern Maine
counts only three or four
136 The electrical geography of northern Maine is well-described in T.Woolf &
B.Biewald, Competition & Market Power in the Northern Maine Market, October
1998, ("Woolf & Biewald") a study prepared for the Commission in response to the
legislative mandate of 35-A M.R.S.A. s. 3206 (3) ("to determine the most
efficient and effective means of ensuring that the portions of this State that
are currently connected to the New England grid through transmission lines that
pass through Canada are connected to the grid in a manner that ensures that
customers in those portions of the State are able to take full advantage of
retail access"). This section relies in part on Woolf & Biewald's analysis.
137 U.S. Department of Justice & Federal Trade Commission, Horizontal Merger
Guidelines, 57 Fed. Reg. 41522 (1992), paragraphs 1.3 -1.4 ("Guidelines").
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generation companies. 138 Generation capacity in northern Maine is currently
divided among MPS, Aroostook Valley Electric Cooperative ("AVEC"),139 and
Alternative Energy, Inc. ("AEI"), approximately as follows:
MPS -- 66 mw
AVEC -- 32 mw
AEI -- 37 mw
In fulfillment of its divestiture obligations under the restructuring
statute, MPS has proposed to sell most of its generation assets, including its
33 mw hydropower facility at Tinker Station, to WPS Power Development, Inc.
("WPS"), a Wisconsin company. 140 This proposed acquisition is the subject of
a pending proceeding at the Commission. However, MPS also holds a "qualifying
facility" contract which entitles it to approximately 18 mw of the capacity of
the Wheelabrator-Sherman ("WS") cogeneration facility. This asset will be the
subject of a separate sale process. Accordingly, for purposes of a
Herfindahl-Hirschman analysis, in-market generation capacity may also be broken
out as follows:
WPS -- 48 mw
WS -- 18 mw
AVEC -- 32 mw
AEI -- 37 mw
In addition to in-market generation, of course, a concentration analysis
must take account of the ability of competitors outside northern Maine to import
power into the region. The transmission capacity of the interties to New
Brunswick is 200 mw; however, MPS assumes for planning purposes (taking possible
outages into account) that these ties are able to carry only 90
138 Perhaps the most striking contrast between the tricounty geographic market
and the New England market to the south is in terms of size. The peak load in
northern Maine, approximately 138 megawatts, represents a tiny fraction
(approximately 0.6%) of the corresponding figure for New England.
139 The proposed acquisition of AVEC by FPL from CMP is currently pending before
the Commission.
140 In fact, the statute does not require divestiture of Tinker Station, which
is physically located in New Brunswick. 35-A M.R.S.A. s. 3204 (1) (C). The
proposed sale of the Tinker assets, however, remains subject to Commission
approval pursuant to 35-A M.R.S.A. s. 3508. Maine Public Service Company,
Petition for Authorization for Sale of Generating Assets, MPUC Docket No. 98-
584 ("MPS Petition").
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mw of power on a firm basis. Accordingly, NBP, which consistently produces a
large surplus above provincial needs, would be in a position to import at least
90 mw of firm power into northern Maine. 141
Under normal circumstances, it might be expected that Hydro-Quebec ("HQ"),
which also has a large surplus available for export and is active as a marketer
elsewhere in the United States, would also be a significant competitor in the
northern Maine market. HQ can gain physical access to northern Maine through New
Brunswick. The capacity of interties linking Quebec to New Brunswick is ample,
easily exceeding those connecting New Brunswick to northern Maine. 142 This
suggests that HQ should be considered a competitor equal to NBP, capable of
importing 90 mw into the northern Maine market. 143
However, there is a serious obstacle to the full participation of HQ in the
market. Although it labels its tariff "open access," NBP charges HQ (and
others) a rate for "through" transmission service (transiting the province) 40%
higher than the rate it charges itself for "out" service (exiting the province).
In addition, the through tariff is significantly (120%) higher than those which
obtain in NEPOOL. Unlike HQ, NBP conducts no marketing activities in the United
States. NBP believes that, in these circumstances, it has no obligation to bring
its transmission tariff into conformity with FERC open access standards. 144
Moreover, NBP's transmission fees and policies are not subject to the oversight
of any Canadian regulatory body. NBP's transmission
141 Woolf & Biewald 8, App. B; see also MPS Petition, Prefiled Direct Testimony
& Exhibits of Dr. Richard C. Tabors, Aug. 7, 1998, Exhibits RDT- 2 -3
("Tabors").
142 Woolf & Biewald App. A.
143 It can be debated whether in this scenario, HQ and NBP should be assigned
90 mw or 45 mw each. We adopt the former because it reflects the fact that both
entities are able to compete for sales up to the 90 mw limit.
144 It is not clear that NBP's interpretation is correct in this regard. NBP
also argues that, in any event, its tariff is FERC-compliant.
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tariff is thus unregulated, discriminatory and subject to unilateral change at
the sole discretion of the utility.
HQ refuses to transmit energy across New Brunswick for its own account
because, as a condition of such transmission, NBP requires reciprocal access to
HQ transmission facilities. Under its own transmission tariff, approved by
Quebec's Regie de l'Energie, 145 HQ may not accord such reciprocal access as
long as the NBP tariff is unregulated and discriminatory. Accordingly, HQ has
no current plans to market power in northern Maine.
Despite its inability to make use of NBP transmission, HQ considers itself
free to, and does, enter "buy-sell" contracts with other entities at the
Quebec-New Brunswick border. Such indirect sales offer at least the prospect
that a marketer other than HQ could use HQ capacity to compete in northern
Maine. As long as NBP retains the unilateral ability to set discriminatory
transmission rates, however, neither HQ nor a proxy using its capacity can be
considered a full competitor in northern Maine for purposes of an HHI analysis.
This same conclusion applies, of course, to any other generator located in
Canada, since the only transmission path available to such participants is
through New Brunswick. Nova Scotia Power Incorporated ("NSP"), for example,
might be considered a potential competitor, although historically it has shown
little interest in exporting power, and does not appear to enjoy a consistent
surplus. In our view, NSP in any event should be excluded from the concentration
analysis for the same reasons as HQ.
Indeed, the same conclusion also applies to all U.S. generators outside
northern Maine, since they too must rely on NBP transmission services to reach
the market. However, New England generators suffer from an additional handicap.
Although the MEPCO line linking New
145 The Regie de l'Energie is the provincial regulatory authority in Quebec.
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England to New Brunswick is capable of carrying approximately 700 mw, it cannot
deliver any firm power south to north. 146 This is because, in the event that
NBP's 650 mw nuclear generator at Point Lepreau suffered an unscheduled outage,
virtually all the power on the MEPCO line which had been contractually earmarked
for the northern Maine market would be siphoned off to serve New Brunswick load.
Thus, as a practical matter, NBP holds a call option on most of the south to
north capacity of the MEPCO line to protect against the consequences of a Point
Lepreau outage. As a result, although they can furnish nonfirm power to northern
Maine, New England generators cannot bind themselves contractually to supply
firm power to tricounty purchasers, and accordingly, would have to be excluded
from the HHI analysis even if New Brunswick adopted a regulated,
nondiscriminatory transmission regime. 147
Against this background, we offer the following HHI data. 148
Figure 4: Current HHI for Northern Maine
Gen. Mw % HHI
MPS 66 29 841
AVEC 32 14 196
AEI 37 16 256
NBP 90 40 1600
TOTAL 2893
Figure 4 above depicts the current market, prior to any MPS divestiture;
it would also accurately describe the market after approved sale to WPS of all
MPS assets, including the WS entitlements. Figure 5 below (which also provides
the basis for Figure 6 below), assumes approval
146 Woolf & Biewald 9; Central Maine Power, Request for Approval of Sale of
Generation Assets, Prefiled Testimony and Exhibits of David M. Conroy, Feb. 20,
1998, 6, Maine PUC Docket No. 98 -058.
147 For this description of the south-north stability constraint on the MEPCO
line, we are indebted to Commission staffer Norman Leonard.
148 These HHI results are very close to those arrived at in Woolf & Biewald App.
B. Table B.1, scenarios 1 & 2; slight discrepancies appear to result from
different methodology for rounding. In his testimony on behalf of MPS, Dr.
Tabors arrived at much lower HHIs for the current market because he erroneously
included HQ and NSP (in one scenario) as well as Westcoast Power and Tractebel
(in another). Tabors, Exhibit RDT-2. Our reasons for excluding HQ and NSP from
the analysis are addressed above; we discuss the entry prospects of Westcoast
and Tractebel below.
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of the proposed sale to WPS, with sale of the WS entitlements to a different
purchaser. In each of Figures 4 and 5, the total HHI indicates an extremely high
level of concentration, giving cause for serious concern with regard to market
power.
Figure 5: Base HHI for Northern Maine
Gen. Mw % HHI
WPS 48 21 441
WS 18 8 64
AVEC 32 14 196
AEI 37 16 256
NBP 90 40 1600
TOTAL 2557
Although the Commission could achieve a reduction in this elevated HHI on
the order of 150 points by ordering WPS to spin off certain assets acquired from
MPS in the context of the pending divestiture, it is clear that this would be
insufficient to allay market power concerns. Only if a means can be found to
effectively include both HQ and NEPOOL in the market will the HHI decline
significantly, as illustrated in Figure 6 below.
Figure 6: Northern Maine with HQ & NEPOOL Participation
Gen. Mw % HHI
WPS 48 12 144
WS 18 4 16
AVEC 32 8 64
AEI 37 9 81
NBP 90 22 484
HQ 90 22 484
NEPOOL 90 22 484
TOTAL 1757 149
Even with the participation of HQ and NEPOOL, the HHI remains disquietingly
high. Although significantly abated, market power concerns will persist until
neighboring Canadian markets are effectively restructured and opened to
competition. Bearing in mind that, in any case,
149 Compare Woolf & Biewald, App. B, Table B.1, scenarios 4 & 5; Tabors, Exhibit
RDT-2, Scenario 1998: Present Market.
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the HHI serves as a screening device rather than an absolute indicator, we turn
in the section following to an analytical assessment of the seriousness of the
market power problem in northern Maine.
D. Market Power in Northern Maine
Analysis of concentration based on current conditions in the northern Maine
market yields an HHI result in excess of 2500. This indicates a high degree of
market power. Moreover, it is not difficult to discern that this market power
resides principally in NBP. NBP's market dominance is both horizontal, deriving
from its ability to offer a large block of surplus power to the northern Maine
market; and vertical, based on its ability to effectively exclude other
potential competitors through its unilateral, unregulated control of
transmission through the province.
Federal antitrust authorities describe markets with an HHI above 1800 as
"highly concentrated." In such markets, a merger which produces an increase in
the HHI of 100 points or more is presumed "likely to create or enhance market
power or facilitate its exercise." 150 This presumption may be overcome by a
showing that other factors render the creation, enhancement or facilitation of
market power unlikely. There are two primary factors to be considered: first,
the relative risk that the market may be unresponsive to normal competitive
forces as a result of coordination, collusion or for other reasons; and second,
the countervailing prospect that new entry could undermine market power and
increase competition. 151
In this report, our focus is not on the competitive effects of a particular
proposed acquisition or merger, but rather on the northern Maine's readiness for
competitive markets, based on current conditions. The analysis, however, is the
same. In the paragraphs below, therefore, we examine the likelihood that market
power in northern Maine could be enhanced by
150 Guidelines paragraph 1.51 (c).
151 Id. paragraphs 2 -3.
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coordinated interaction among market participants or other factors; and the
extent to which new entry may be relied upon to counteract market power.
1. Responsiveness of the market to competitive forces. Hitherto
subject to comprehensive regulation, the electric industry is a relative
newcomer to competition. The need to ensure system reliability, among other
factors, has accustomed the industry to a high degree of coordination among
firms. Old habits often die hard. It is likely that there is a substantially
increased risk of habitual coordination, and perhaps an augmented tendency to
illegal collusion as well, in a previously regulated, newly competitive
industry. 152
In northern Maine, the risk of coordination and collusion is likely to be
greater in inverse proportion to the small number of market participants. An
additional factor to be considered is NBP's current policy determination that
it will not market electricity for its own account within the United States.
153 Open access rules may well require NBP to alter its discriminatory
transmission rate structure, eliminating most or all of the discrepancy between
its "through" and "out" tariffs. 154 As a result, while it remains willing to
sell power to U.S. marketers at the frontier, NBP will not itself deliver power
within the United States. If NBP were to contract to deliver power at the border
to an entity which was already a participant in the northern Maine market as a
generator, competition in the wholesale market could be significantly reduced.
Under these
152 Prepared Statement of Robert Pitofsky, Chairman, Federal Trade Commission,
Hearing Before the Committee on the Judiciary, U.S. House of Representatives,
105th Congress, First Session, June 4, 1997 (some industry participants,
accustomed to coordination, may attempt to conserve comfortable aspects of a
regulated environment; would not discount the possibility of cartel behavior to
protect entrenched positions); see also, R. Pierce, Antitrust Policy in the New
Electricity Industry, 44 (increased risk of collusion, since electric
wholesalers know all about each other's price strategies and cost structures).
153 In a conversation with the Department on July 29, 1998, Darrell Bishop, NBP
Director of Bulk Power Marketing, stated that "reciprocity is a concern" and
that as a result, NBP has no current plans to market power at retail in Maine.
154 Federal Energy Regulatory Commission, Order No. 888.
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circumstances, the already high concentration index reported above might
represent a serious understatement. 155
Equally significant, perhaps, is the risk that the market could suffer from
rigidity, and might lack the ability to respond to competitive signals.
Currently, northern Maine lacks access to an auction market. The primary trading
mechanism is likely to be bilateral contracts. These may be supplemented by spot
transactions if northern Maine gains ready access to the spot market to
be administered by ISO-NE, or develops its own. Although not a panacea, 156
access to a well-designed spot market would probably increase the responsiveness
of the northern Maine market to competitive forces. 157
2. New entry. Significant difficulties confront the developers of the
many projects to construct new generation facilities now on the drawing board
in New England. There is a real probability, however, that some fraction of
these projects will be built, and that some new entry will occur. Whether this
prospect is likely to be realized on a sufficiently accelerated schedule to
mitigate market power in the short or medium term remains an open question. 158
155 Such a contract would merit careful analysis to determine whether it
violated the prohibition against contracts or combinations in unreasonable
restraint of trade. 10 M.R.S.A. s. 1101. Accordingly, NBP may wish to seek the
informal approval of the Department before entering into a contract of this
nature.
156 As we discuss in the section relating to horizontal market power in New
England above, spot markets may also fall prey to market power. There is even
greater reason for concern with regard to strategic behavior (economic
withholding) in a northern Maine spot market than there is in the much less
concentrated New England market. See Petition of Maine Public Service Company
for Authorization for Sale of Generating Assets, Maine PUC Docket No. 98 -584,
Testimony of Dr. Aleksandr Rudkevich On Behalf of the Maine Public Advocate,
Part II ("Rudkevich").
157 See Woolf & Biewald, 14 ("spot market provides greater opportunities ... to
participate in the market, and to reach a large number of customers easily and
quickly. A spot market provides electricity buyers greater opportunities for
purchasing the lowest-cost electricity at all times. A spot market also provides
real-time, consistent, reliable and transparent information about market prices
and conditions, thereby promoting efficient market behavior [citation
omitted]").
158 See discussion above.
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In northern Maine, by contrast, the issue is whether there is likely to be
any new entry at all. No new projects are currently on the drawing boards. 159
Northern Maine will not have access to the natural gas pipelines which will
provide fuel to new entrants elsewhere in New England. Moreover, northern Maine
is an unattractive venue for the construction of new generation capacity because
of its remote geography and its dependence on NBP's high-priced transmission
services and unilaterally-determined, discriminatory rates. In addition, the
lack of access to a spot market may make it more difficult for new entrants to
contemplate participating in the northern Maine market. 160
The prospect of new entry from New Brunswick is also discouraging. Under
New Brunswick's Electric Power Act, NBP enjoys the exclusive right to generate
power in the province. Private developers must obtain special authorization from
the Lieutentant-Governor in Council to construct or operate any generation
facility with a capacity greater than 500 horsepower. 161 In the recent past,
for example, Fraser Paper Company received such authorization to construct a 38
mw cogeneration plant, whose output is fully contracted to NBP.
More recently, and more significantly for present purposes, Westcoast Power
has obtained the requisite gubernatorial authorization to move ahead with a
project to repower a 250 mw unit at NBP's oil-fired Courtenay Bay facility (near
St. John) to accommodate natural gas. An optimistic schedule would bring this
facility on line by late 2000. With NBP as minority partner, Westcoast will hold
an 80% controlling equity stake in the project, and plans to market electricity
in New England. This could include sales into northern Maine. However, the
project's output is
159 Although the Loring Development Authority is currently attempting to auction
a mothballed 40 mw coal-fired generator (capable of conversion to oil) at the
former air base, it remains to be seen whether there will be any takers.
160 Woolf & Biewald, 14.
161 New Brunswick Electric Power Act sections 32 (1) through 32 (4).
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already fully contracted to NBP for five winter months each year. 162
Accordingly, the ability of this project to alleviate market power pressure on
northern Maine is limited, even if Westcoast's Courtenay Bay operations are kept
strictly independent of NBP. 163
While another gas-fired project, in northern New Brunswick, is in the early
stages of discussion and preparation, this project has not yet received
gubernatorial authorization, and appears to be subject to significantly greater
contingencies, including the construction of a 150-mile lateral gas pipeline.
It is unclear whether NBP would have an equity position in this project, which
is planned for a site adjacent to NBP's existing coal-fired facility at
Belledune. In any event, the developer, Tractebel Power Inc., expects to market
all of its planned 350 mw in New England, and has no present intention to
compete for sales in northern Maine. 164
In sum, the prospects for new entry into the northern Maine market are
poor. In light of this assessment, it becomes critical that effective remedies
for market power be found before the inauguration of retail choice in northern
Maine.
E. Remedies for Market Power in Northern Maine
Under current conditions, the wholesale electricity market in northern
Maine is extremely concentrated, indicating a high degree of market power. In
the microcosmic tricounty environment, there is a danger that coordination,
collusion and, not least, a lack of market flexibility will further undermine
competition. The prospect of new entry is limited and unreliable. A lack of
competition at the wholesale level is likely to have an adverse impact on retail
prices.
162 Maine Public Service Company, Response to Houlton Water Company's Data
Request No. 1, Maine PUC Docket No. 98 -584, Sept. 16, 1998 , Question
HWC-01-06.
163 Westcoast may have difficulty obtaining FERC authorization to charge
market-based rates, in view of the 20% NBP stake, and NBP's discriminatory
transmission regime.
164 Based on a conversation between the Department and Robert Dubois of
Tractebel, September 29, 1998.
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Under these inauspicious circumstances, it may be questioned whether Maine
should act legislatively to postpone retail choice in the northern section of
the State.
Before embracing this course of action, however, the Legislature should
give due consideration to the feasibility and efficacy of other available
remedial measures. Accordingly, in the paragraphs below, we review Maine's
jurisdictional ability to promote: (a) an emerging solution which offers the
prospect of moving firm power north from New England along the MEPCO line; (b)
the transition to a regulated transmission regime in New Brunswick; (c) access
to a spot market for tricounty purchasers; (d) construction of alternative
transmission connecting northern Maine to New England and Quebec; and (e)
interim wholesale price regulation as a last resort short of suspending retail
choice.
1. How northern Maine can obtain firm power from New England. On
September 11, 1998, NBP signed a contract to supply MPS with "tie line
interruption service," or back-up power. The power will be supplied on an
as-needed basis, without the need to reserve capacity, at a price equal to 120%
of cost. The contract expires on February 28, 2005. Access to this back-up power
will ostensibly enable MPS to enter contracts to sell firm power in northern
Maine on the basis of nonfirm imports from New England over the MEPCO line. 165
In a subsequent meeting with the Commission and representatives of the
Executive Branch, NBP made known its willingness to enter into similar
contracts, for a similar term, with any party. 166 NBP has since confirmed
this offer in separate conversations with Woolf & Biewald,
165 Administration Committee Agreement, Maine Public Service Company-NB Power,
Tie Line Interruption Service, dated August 25, 1998.
166 The meeting took place in Bangor, September 17, 1998, and was attended by
Gregory Nadeau, Assistant to the Governor, Thomas Welch, Commission Chair,
Stephen Ward, Public Advocate, Gordon Weil, consultant to the Public Advocate
as well as Houlton Water Company and Van Buren Light & Power District, Laurie
Lachance, State Economist, and Peter Louridas, MPS. Attending from New Brunswick
were Don Barnett, Assistant Deputy Minister for Energy, Jocelyne Mills,
Department of Intergovernmental & Aboriginal Affairs; and for NBP, Archie
Gillis, Senior Vice President, Stewart MacPherson, Vice President Corporate
Affairs, Bill Marshall, Director, Strategic Planning, and Darrell Bishop,
Director, Bulk Marketing.
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and with the Department. 167 Further, NBP has indicated its willingness to
similarly contract to supply needed ancillary services, viz., Automatic
Generation Control ("AGC", or "load following"), Ten-Minute Spinning Reserve
("TMSR"), Ten-Minute Nonspinning Reserve ("TMNS") and Thirty-Minute Operating
Reserve ("TMOR") to all comers. 168 If NBP follows through on this offer, the
effect will be to give any party interested in marketing power in northern
Maine the ability to do so on the basis of nonfirm imports from New England over
the MEPCO line, backed by NBP's "tie-line interruption service" together with
needed ancillary services. This prospect, if realized, would effectively remove
the south-to-north constraint on the MEPCO line, and significantly improve
northern Maine's access to generators in New England.
NBP's offer is obviously a very significant development, and clearly
indicative of very considerable goodwill on the part of our Canadian neighbors.
However, by itself, NBP's offer remains insufficient to provide a reliable link
to New England. Except insofar as it is now contractually committed to provide
back-up power (though apparently not ancillary services) to MPS, NBP has as yet
placed itself under no obligation to follow through on its offer. While we
are confident that NBP means what it says, we submit that the State of Maine
cannot make fundamental policy decisions with regard to restructuring in
northern Maine on the basis of mere representations.
NBP's offer provides a valuable opportunity, which should be welcomed and
acted upon. The State should seek a way to respond positively to NBP, and to
devise a mutually acceptable means to transform its nonbinding offer into
something more solid. For example, the State might,
167 Woolf & Biewald 26. In a conversation with the Department on September 24,
1998, Darrell Bishop of NBP reiterated NBP's offer to contract to supply back-up
power to any entity.
168 Specifically, in response to a question from consultant Gordon Weil at the
September 17 meeting, Darrell Bishop stated that NBP would provide load
following and all ancillary services needed. Because of the south to north
constraint, AGC, TMSR and TMNS from New England are unavailable to northern
Maine on a firm basis. NBP's market power in these products is, accordingly,
extremely elevated; the proposed contracts would, however, adequately mitigate
that market power.
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through legislation, authorize all northern Maine t&ds to enter into contracts
with NBP for "tie-line interruption services" and needed ancillary services for
a five-year period. 169 The legislation could further empower the Commission
to require the t&ds to provide the back-up power and ancillary services supplied
by NBP pursuant to these contracts to any marketer seeking to import power into
northern Maine from New England, at the t&d's cost. It would then remain for
NBP to actually enter into such contracts with the t&ds. 170 The contracts
could then be presented for the Commission's approval.
This mechanism would limit NBP's costs by requiring only four contracts,
instead of a multiplicity of transactions. In addition, requiring contracts with
the t&ds rather than marketers brings the back-up power and ancillary services
within Maine's regulatory jurisdiction. If NBP (or MPS) retained the ability to
select which marketers would receive these essential commodities, and to
determine their price, the problem of market power would remain unsolved.
Adoption of the legislative measures described above is therefore strongly
recommended.
2. The prospect of a regulated transmission regime in New Brunswick.
With these contracts and the related legislation in place, a significant link
to New England would have been forged. Nevertheless, the prospect of NBP
wielding market power in northern Maine will remain as long as NBP retains the
unregulated, unilateral ability to set discriminatory transmission rates.
169 The northern Maine t&ds include MPS, Houlton Water Company, Eastern Maine
Electric Cooperative, and Van Buren Power & Light District. Note that the
legislative changes needed for the latter three, which are consumer-owned
utilities, may differ somewhat from those relating to MPS. It may be questioned
whether NBP should expect to profit from these transactions to the extent of the
20% markup reflected in the MPS contract. It can be argued that NBP derives an
uncompensated benefit from the its ability to draw on MEPCO in the event of an
outage at Point Lepreau. It is this benefit to NBP which causes the constraint
on the MEPCO line, and prevents firm power from reaching northern Maine from New
England. By providing back-up power and ancillary services to northern Maine,
the argument runs, NBP is merely balancing the account.
170 NBP Director of Strategic Planning Bill Marshall indicated at a meeting at
the Commission on November 12, 1998 that NBP had no conceptual difficulty with
this proposal.
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The problem is straightforward: NBP, and jurisdictionally, the province of
New Brunswick, control the only existing transmission route linking northern
Maine to New England, Quebec, Nova Scotia, and more distant points. NBP's
strategic control of this transmission route is not tempered by regulation of
any kind, U.S. or Canadian, federal or provincial. Currently, NBP is exercising
that control to impose discriminatory rates. Specifically, the "through"
transmission service offered to marketers transiting the province is
approximately 40% higher than the "out" rate which NBP charges itself for
transmission exiting the province. 171 Theoretically, there is nothing to
prevent NBP from acting unilaterally to further increase its "through"
transmission tariff to any level it wishes. In sum, NBP possesses the ability,
should it so desire, to exclude competing New England, Quebec or Nova Scotia
generation from the northern Maine market.
In practical terms, the situation is more complex. There are signs that
NBP, and provincial authorities, are moving toward a regulated regime. It is
significant, for example, that (a) NBP has posted its transmission tariff on
the Internet using FERC's OASIS information system; (b) NBP represents publicly
that its through and out rates are cost-based; 172 and (c) in response to
"concerns expressed by potential transmission customers," NBP has publicly
pledged that any increase in its tariffed rates "shall not be greater than the
rate of inflation as measured by the Consumer Price Index in New Brunswick until
such time [as] an independent regulatory body having jurisdiction over the
tariff is put in place." 173 Finally, NBP and provincial government
171 We doubt that this discriminatory regime would pass muster under FERC open
access rules.
172 In conversations with the Department on June 5, June 8, and July 29, 1998,
Darrell Bishop and Arden Trenholm of NBP stated that the wheeling tariffs were
cost-based. NBP apparently justifies its discriminatory rate structure by
asserting that only importers derive benefit from the tie lines connecting New
Brunswick to New England and other regions. NBP denies that it also derives
benefit, despite the undeniable fact that, in the event of a Point Lepreau
outage, the New Brunswick system would draw heavily on the MEPCO tie.
173 Tariff Clarification, February 27, 1998, http://oasis.nbpower.com/WhatsNew.
Of course, the pledge remains unilateral, and could be withdrawn, but is
unlikely to be withdrawn lightly. Indeed, NBP has reportedly indicated (per
consultant Gordon Weil) that it will waive the escalator and freeze transmission
rates.
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officials have indicated to the Commission and representatives of the Executive
Branch their belief that provincial legislation subjecting NBP transmission
rates to independent regulatory oversight is likely to be in place by the summer
of 1999. 174
These are encouraging signs. In addition, the Commission and the Department
will continue to explore whether there is any prospect that NBP would subject
itself to FERC open access standards by applying to that agency for market-based
rate authority. This step would offer a dual benefit for Maine: in addition to
nondiscriminatory transmission rates through the province, it would also permit
NBP to enter retail markets in northern Maine (and other sections of the State
as well) as a marketer in its own right. The Commission and the Department in
any event will continue to carefully monitor, and inform the Legislature
concerning, further developments in this area.
In the meantime, pending either an NBP FERC filing or provincial
legislation or both, an interim solution to the problem of NBP's unregulated,
discriminatory transmission regime has been proposed. The proposal is
straightforward: in addition to contracting with northern Maine t&d companies
to provide tie-line interruption and needed ancillary services, NBP should also
offer to contract with the t&ds to provide transmission services at a fixed
price. Preferably, the agreed price should be a rate equal to NBP's lower "out"
rate, rather than its higher "through" rate. 175 In effect, NBP could elect to
treat northern Maine as if it were a part of New Brunswick for transmission
purposes. Again therefore, there is a need for legislation authorizing the t&ds
to enter into these transmission services contracts subject to Commission
approval, and empowering
174 This representation was made at the September 17 meeting. In a conversation
with the Department on September 24, 1998, Darrell Bishop confirmed this, and
indicated that June, 1999 was the target date for the passage of legislation in
this regard.
175 It is not clear whether this change would satisfy the conditions imposed on
HQ by its own tariff, thereby permitting it to serve northern Maine directly.
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the Commission to require the t&ds to pass the transmission services on to
marketers at cost. Adoption of these measures is strongly recommended.176
3. Access to a spot market. Northern Maine has no ISO, and no spot
market. Development of an ISO to govern transmission in the New Brunswick and
northern Maine and Maritime region would certainly represent a desirable
antidote to NBP's vertical market power astride regional transmission routes.
An ISO could also function, as in New England, as the administrator of a
regional spot market. However, an ISO for the Maritime region is not likely to
be developed in the immediate future. If such an institution does eventually
come into being, it will be as an element of a regional restructuring process.
The policy discussion which could lead to that process has only just begun in
New Brunswick. 177
During the summer of 1998, a "Northern Maine Working Group" ("NMWG"),
comprising NBP and the northern Maine t&ds, was formed to study options for
northern Maine pending creation of a regional Maritime ISO. In this context, NBP
has indicated that although it is not yet prepared to discuss formation of an
ISO, it would consider cooperating with MPS and other utilities in northern
Maine to set up a "bulk power system administrator" ("BPSA") which, among
other functions, might operate a day-ahead spot market. 178
Most recently, MPS offered that it would function as the BPSA, and would
operate a spot market modeled as closely as possible on the New England market.
179 However, both the
176 The proposal originated with consultant Gordon Weil; NBP is aware of it. A
meeting among NBP, the Commission, the Department and other stakeholders to
discuss the overall contractual approach to tie-line interruption services,
ancillary services and transmission services has been scheduled for December 16
- -17, 1998.
177 See Savoie & Hay.
178 See Memorandum, W. Gerow to Northern Maine Working Group on Settlement,
August 17, 1998 (at working group telephone conference on August 13, 1998, NBP
"took exception [to] use of the term ISO", and to "the notion that we were
talking about the Maritime Control Area as a whole").
179 See Northern Maine BPSA Draft Framework Document (undated, without
attribution). This was presented by Fred Bustard of MPS at a meeting between
representatives of NMWG, the Commission and the Department on November 12, 1998.
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Department and Houlton Water Company ("HWC") have voiced concerns with respect
to this concept.180 In particular, both the Department and HWC expressed the
view that a BPSA operated by MPS might not be sufficiently independent; both
were also concerned that emulation of the NEPOOL market system may not be
appropriate in the northern Maine context.
Computer simulation modeling suggests that strategic behavior, or gaming,
may drive up wholesale prices in the New England spot market. Recent testimony
before the Commission on behalf of the Maine Public Advocate indicates that such
behavior will pose an even greater problem in the more concentrated, microcosmic
northern Maine environment. 181 It may be that northern Maine is too small to
support its own spot market, and that this should await regional restructuring
which includes New Brunswick and Nova Scotia, or enhanced transmission
connecting northern Maine to New England. 182
It is our understanding that the NMWG has engaged expert consultants to
advise it with regard to available BPSA options. The Commission and the
Department look forward to working further with NMWG to develop a settlement
system appropriate to northern Maine's special circumstances. In due course,
when a workable concept has been developed and agreed upon, there may be a need
for legislation. The Commission and the Department will keep the Legislature
informed in this regard.
In the meantime, what is essential is that northern Maine have access to
a spot market capable of receiving and transmitting price signals, and lending
flexibility to the market. If NBP binds itself to provide back-up power,
ancillary services and reasonably-priced transmission
180 Letter, J. Clark to F. Bustard dated November 13, 1998; Letter, F. Ackerman
to F. Bustard dated November 13, 1998.
181 Rudkevich, 2 (generation owners could achieve very significant market power
by capacity withholding).
182 See FTC Attorney Warns Of Single State ISO, Restructuring Today, Oct. 8,
1998 (J. Hilke quoted to the effect that a single state ISO is too small -- with
very few, if any exceptions -- because "it may not encompass enough generating
firms to mitigate generator market dominance problems and enhance reliability").
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services to all northern Maine t&ds, the beneficial influence of New England
spot market pricing will be felt in northern Maine.
4. Alternative transmission. The benefits of retail choice in northern
Maine cannot be assured unless more reliable access to New England generators,
as well as to HQ generation and the New England spot market, can be provided.
As we conclude above, the requirement of access to New England, and perhaps
Quebec as well, can be adequately fulfilled if NBP commits itself: (a)
contractually to supply back-up power and needed ancillary services to all
northern Maine t&ds, thereby effectively eliminating the south to north
constraint on the MEPCO line; and (b) to fair, nondiscriminatory transmission
rates. 183 If NBP and the provincial government take both of these actions (as
they have indicated they will), there will be good grounds for optimism with
regard to the competitive health of northern Maine markets.
Another way to provide northern Maine with access to Quebec and New England
generation sources would be through the construction of new transmission lines.
Alternative transmission which would remove the MEPCO constraint, or bypass New
Brunswick, would clearly offer long term benefits. If events unfold positively,
there should be no immediate need to construct alternative transmission lines
linking northern Maine to Quebec and New England. However, alternate
transmission remains an important long-term option. Moreover, if NBP's
cooperation cannot be secured, or experience demonstrates the persistence of
market power problems despite such cooperation, it may become necessary to focus
more intensively on this option.
183 Whether contractually, or by means of a filing with FERC or appropriate
provincial legislation establishing an independent, regulated, nondiscriminatory
transmission regime.
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The Commission and the Department will therefore monitor and continue to
inform the Legislature concerning (a) feasibility studies being conducted by
Transenergie 184 with regard to a proposed transmission line which would
connect HQ directly to MPS through Madawaska; and (b) BHE plans for a new line
connecting NEPOOL to NBP as an alternative to MEPCO. 185 Although not
immediately essential, it is clear that the construction of each of the proposed
new lines would enhance the competitiveness of northern Maine markets. In due
course, if necessary, the Department and the Commission may recommend
legislation to promote the completion of these or other transmission projects.
5. Wholesale price regulation. We currently expect that it will prove
possible, with the anticipated cooperation of NBP, to overcome the
south-to-north constraint on the MEPCO line, thereby permitting NEPOOL
participants to effectively enter the northern Maine market. In addition, the
prospect for transition to a regulated, nondiscriminatory transmission
regime in New Brunswick in the near to medium term appears promising. However,
these developments are largely outside Maine's jurisdictional control, and
cannot be assured.
If neither of these hoped-for developments is realized, northern Maine's
wholesale market will remain extremely concentrated, and subject to a high
degree of market power. As we have noted, it may be questioned whether, in these
circumstances, retail choice should proceed as scheduled in the tricounty area.
If wholesale prices rise in a concentrated market, there would almost certainly
be an adverse price impact on retail prices as well. To guard against this
eventuality, as a final remedial measure short of postponing retail choice, we
submit that the Legislature should authorize the Commission to impose wholesale
price regulation on the northern Maine market, if warranted, to the full extent
of the State's jurisdiction.
184 Transenergie is HQ's transmission subsidiary.
185 BHE proposes to sell its rights in this regard as part of the proposed
divestiture to PP&L.
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The precise extent of Maine's jurisdiction to regulate wholesale rates in
northern Maine is less than crystal clear. Certainly, FERC possesses plenary and
exclusive authority to regulate wholesale rates with respect to transactions
entered upon by public utilities (i.e., the owners of jurisdictional facilities)
in interstate commerce.186 See, e.g. Nantahala Power & Light Co. v. Thornburg,
476 U.S. 956, 966 (1986); Maine Yankee Power Company v. Maine Public Utilities
Commission, 581 A.2d 799, 803 (Me. 1990).
The Supreme Court has held that the Federal Power Act "grants [FERC]
jurisdiction of all sales of electric energy at wholesale in interstate commerce
not expressly exempted by the act itself." Federal Power Commission v. Southern
California Edison Company, 376 U.S. 205, 210 (1964). Strikingly, there is an
express exemption which would appear to be tailor-made for northern Maine's
special circumstances. A subsection added to the Federal Power Act by a 1953
amendment provides:
The ownership or operation of facilities for the ... sale at
wholesale of electric energy which is ... generated in a
foreign country and transmitted across an international
boundary into a State and not thereafter transmitted into
any other State, shall not make a person a public utility
subject to regulation as such .... The State within which
any such facilities are located may regulate any such
transaction insofar as such State regulation does not
conflict with the exercise of the Commission's powers
under or relating to subsection 202 (e). 187
186 The Federal Power Act, 16 U.S.C. s. 824d, requires that all rates received
by a public utility for the sale of energy subject to FERC jurisdiction be just
and reasonable. Under a coordinate provision, 16 U.S.C. s. 824 (b), FERC
possesses jurisdiction over all facilities for transmission or wholesale sale
of energy in interstate commerce, but not over facilities for generation, local
distribution or transmission in intrastate commerce. A public utility is defined
as any person owning such jurisdictional facilities. 16 U.S.C. s. 824 (e).
Transmission in interstate commerce occurs when energy is transmitted from a
state and consumed outside that state, but only to the extent the transmission
occurs in the United States. 16 U.S.C. s. 824 (c).
187 16 U.S.C. s. 824a (f). The subsection referred to as section 202 (e), 16
U.S.C. s. 824a (e), requires that a permit be obtained from FERC prior to any
export transmission.
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This language explicitly exempts a category of energy producers from FERC
wholesale rate jurisdiction, viz., those who generate power in a foreign
country, transmit it into a state "and not thereafter ... into another State."
There may be entities -- for example NBP and WPS 188 -- which generate power in
Canada, and transmit it across the frontier into northern Maine for wholesale
and ultimately retail disposition there, with no prospect that it will ever
reach New Hampshire or any other U.S. jurisdiction. It would appear that the
Federal Power Act expressly places such transactions within Maine's regulatory
jurisdiction. 189
As a practical matter, the ability of the Commission to impose effective
price regulation would be constrained not only by production costs, but also by
prevailing prices in southern New England markets. However, wholesale regulation
tempered by reference to New England pricing would be appropriate in any case
in that it would mimic the price effect on northern Maine of effective access
to the New England market.
Wholesale rate regulation would be available to the Commission only as a
last resort, to combat market power. Such residual regulatory authority should
not in any way discourage new wholesalers or generators from participation in
the region. If exercised, its practical effect would be no more than to limit
market participants in northern Maine to the profit levels they might expect to
realize in New England. Yet even if it is never exercised, its availability can
operate as an important deterrent to market power abuse in northern Maine.
F. Recommendations
188 Tinker Station, currently the subject of a proposed divestiture by MPS to
WPS, is located in New Brunswick.
189 We are investigating whether certain intrastate wholesale transactions
within northern Maine may also be subject to state regulation. Specifically,
where an intrastate sale for resale made by an entity without interstate
facilities involves no amount of energy from out-of-state sources, the
transaction may be subject to Maine's jurisdiction. See California Edison, 376
U.S. at 209 fn. 5 (if any amount of out-of-state power reaches the wholesale
buyer, the sale is subject to FERC jurisdiction, using an "engineering and
scientific rather than a legalistic or governmental test").
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1. The Legislature should authorize northern Maine t&d companies to enter
contracts with NBP for at least a five-year term for the purchase of back-up
power, needed ancillary services and transmission services; and empower the
Commission to require northern Maine t&d companies to pass such back-up power,
ancillary services and transmission services through at cost to retail marketers
and other customers.
2. The Legislature should empower the Commission to impose wholesale price
regulation in northern Maine, if warranted by market power concerns.
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VI. MARKET POWER IN RENEWABLES
A. Summary
Maine's restructuring statute requires energy marketers to demonstrate, as
a condition of licensing, that at least 30% of their supply portfolio for sales
in Maine consists of renewable resources (as defined in the statute). This
so-called Renewable Portfolio Standard ("RPS") creates a product market distinct
from generic energy. Two geographic markets are analysed here for the presence
of market power in renewables: New England and northern Maine.
The northern Maine market is highly concentrated; the New England market
moderately so. In each case, a current condition of oversupply operates to
negate market power. However, there is a potential for increased demand for
renewables in the region, and the current oversupply may prove transitory.
If the supply picture tightens, market power could become problematic in
both markets. The principal threat is that of vertical retail exclusion:
participants holding high market shares in renewables would become the
gatekeepers to Maine's retail energy markets, selecting or vetoing their retail
competitors, and determining the prices at which they could compete. This threat
is accentuated by a lack of flexible mechanisms for trading renewables, such as
tradable credits, or a power exchange.
We recommend that the Commission be legislatively empowered to suspend or
reduce the RPS in any section of the State on market power grounds.
B. Product and Geographic Markets
Maine's restructuring statute requires that, as a condition of licensing,
competitive electricity providers demonstrate that no less than 30% of their
portfolio of supply sources for retail electricity sales in the State are
accounted for by renewable resources as defined in the statute. The statute
defines the term "renewable resource" as
a source of electrical generation that generates power
that can be physically delivered to the control region in
which [ISO-NE] has authority over transmission and that
... qualifies as a small power production facility under
[applicable FERC rules] ... [or] qualifies as a qualifying
cogeneration facility under [applicable FERC rules] and
was constructed prior to January 1, 1997; or ... [w]hose
total power production capacity does not exceed 100
megawatts and that relies on one or more of the following:
(1) Fuel cells; (2) Tidal power; (3) Solar arrays and installations;
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(4) Wind power installations; (5) Geothermal installations;
(6) Hydroelectric generators; (7) Biomass generators; or
(8) Generators fueled by municipal solid waste in conjunction
with recycling. 190
This so-called "Renewable Portfolio Standard", or "RPS," effectively results in
the creation of a product market distinct from energy, capacity and ancillary
services. As a result of the RPS, the wholesale market for renewable energy must
be separately analysed for the presence of market power.
Under the Commission's proposed rulemaking, 191 the appropriate
geographic markets in which to assess wholesale market power in renewables are
New England and northern Maine. 192 If the Commission had chosen to implement
a system of tradable renewable credits, 193 the effect would have been to
combine the New England and northern Maine markets. However, the Commission
instead selected a contract path tracking mechanism, requiring that energy used
to satisfy the RPS be "physically delivered to," and "recognized as serving
electricity load" within, either of two control areas, New England and the
Maritimes (within which northern Maine is located). 194
190 35-A M.R.S.A. s. 3210 (2).
191 Renewable Resource Portfolio Requirement (Chapter 311), Maine PUC Docket No.
98 -619 ("Renewable Rule").
192 In view of the fact that compliance is measured over a twelve-month period,
a load pocket would have to affect a significant number of hours over a full
year in order to affect the delineation of the appropriate geographic market in
which to assess market power.
193 A tradable credit system would have involved the creation of a secondary
market in renewable "tags", where the renewable attribute of energy generated
from a specific facility could be sold separately from the energy itself. The
Commission's proposed rule rejects tradable credits primarily on the ground that
such a system would be incompatible with regional efforts to implement uniform
consumer disclosure requirements. See Regulatory Assistance Project Issues
letter, May 1998; T. Austin, D. Moskovitz & C. Harrington, Uniform Disclosure
Standards for New England: Report & Recommendation to the New England Regulatory
Commissions, October 6, 1997.
194 Since electrons are themselves untraceable within a given grid using current
technology, contract path tracking follows the paper trail left by electricity
sales to determine the source of the electrons. This contrasts with a tradable
credits system, which would track only the separately sold renewable tag or
attribute of renewable energy. See Renewable Rule paragraph 4(B).
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The proposed rule does not combine the two markets, since a marketer active, for
example, only in northern Maine (and not in southern and central Maine) must
shop for renewable resources deliverable to northern Maine, and would be
affected by the level of concentration and market power which obtained in that
market. However, the rule mitigates market power to some extent by allowing a
marketer active in both markets to satisfy the RPS on the basis of the statewide
average of its renewable resource component. While this is beneficial from the
perspective of marketers active in all sections of the State, it does not change
the fact that northern Maine and New England continue to require separate
analysis for market power in renewables.
C. Concentration Analysis
In this section, we apply a Herfindahl-Hirschman analysis to evaluate
levels of concentration in relevant renewables markets.
1. Market participants. All renewable capacity in each market is
included in our HHI analyses. Recent or pending divestitures in the New England
market (USGen acquisition of NEES assets; FPL acquisition of CMP assets) and
northern Maine (WPS acquisition of MPS assets) are reflected. However, to
attempt to account for NU's recently announced intention to divest certain
capacity in Connecticut and Massachusetts would be speculative.
BHE, CMP and MPS continue to hold certain NUG contracts which are the
subject of a sale process separate from the pending acquisitions of generation
assets by PP&L, FPL and WPS, respectively. A rulemaking with respect to that
process is currently pending at the Commission. While the HHI should therefore
ascribe these assets to BHE, CMP and MPS, in evaluating the
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results, account should be taken of the fact that the Commission retains the
ability to require piecemeal sales of the NUGs on market power grounds.
We allow for a moderate level of imports from NYPP. However, there are good
grounds to exclude from the HHI calculations all renewable capacity which might
appear to be available from Quebec. Currently, HQ exports to the U.S. are drawn
from system surplus. Although it possesses approximately 659 megawatts of
hydroelectric capacity in facilities under the 100 mw statutory ceiling, HQ
faces regulatory barriers which will likely prevent this power from being
marketed in New England on a resource-specific basis. 195 In a telephone
conference with the Department, a senior HQ executive explained that small,
low-cost hydro cannot be removed from the system mix without an impact on the
Quebec rate base. As a result, she stated, "HQ does system power sales, not unit
contracts .... We are not going to dedicate these units to export." Any change
in this system was characterized as "highly unlikely." 196
NBP's ability to earmark qualifying resources for export appears doubtful
for similar reasons. In any event, it appears that NBP possesses a relatively
limited stock of renewable capacity. 197
195 In particular, such resource-specific exports would be inconsistent with the
terms of HQ's current export licenses, issued by Canada's National Energy Board.
Further, dedication of particular resources to export would require a ruling by
Quebec's Regie de l'Energie, the provincial regulatory authority.
196 The quotations are from Johane Meagher, speaking in the course of a
telephone conference with the Department and its consultants on June 11, 1998.
Meagher also noted that the interties connecting Quebec to New England are fully
booked through 2001, with the exception of transmission through New Brunswick,
which HQ eschews for policy reasons (discussed above). Following the call, HQ
provided data by fax indicating that hydro qualifying under the Maine RPS
represents approximately 3.3% of the HQ system mix. Although HQ system exports
qualify to this extent under the Maine RPS and the proposed rule, we
nevertheless exclude them from the HHI because HQ cannot market its system mix
as a qualifying renewable.
197 In telephone conversations and fax communications with the Department on
June 5 and June 8, 1998, Darrel Bishop, NBP Director of Bulk Power Marketing,
listed 89 mw of qualifying NBP hydropower. He also referenced certain other
hydro units under contract to NBP (approximately 25 mw); and some thermal
capacity. It was not clear that any of the thermal capacity would be considered
renewable under the statutory definition.
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Finally, the ability of New England renewable resources to gain access to
northern Maine is uncertain. The MEPCO constraint presumably does not affect the
ability of northern Maine marketers to obtain renewables from New England on an
interruptible basis, and such imports could be counted toward the twelve-month
30% requirement. Nevertheless, New England renewables remain dependent on NBP's
unregulated transmission regime for access to northern Maine. As we indicate
above, however, it now appears that the prospects for opening northern
Maine to sales from New England are favorable.
2. HHI data. In light of the foregoing, we offer the following HHI
data. 198 Two HHIs are offered to provide perspective with regard to northern
Maine, reflecting the uncertain participation of New England imports in this
market.
Figure 7: Northern Maine Renewables
Gen Mw % HHI
AVEC 30 25 625
AEI 37 31 961
MPS 18 15 225
WPS 33 28 784
TOTAL 118 2595
Figure 8: Northern Maine Renewables with New England Imports
Gen Mw % HHI
AVEC 30 20 400
AEI 37 25 625
MPS 18 12 144
198 These are based on the workpapers of Bruce Biewald and Timothy Woolf. Note
that while at least one expert suggests that HHIs should be truncated to cap
market shares at the level of estimated demand, we believe this would be
inappropriate, in this instance. The level of demand for renewables is fluid and
uncertain. Accordingly, demand and supply dynamics should be considered in
evaluating HHI results, rather than incorporated into them. See CMP Request for
Approval of Sale of Generating Assets, Prefiled Testimony & Exhibits of Joe D.
Pace, February 20, 1998, Maine PUC Docket No. 98 -058 at 25-27.
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WPS 33 22 484
NEPOOL 30 199 20 400
TOTAL 148 2053
199 This table shows a single New England participant, capped at 30 mw
(one-third of available tie capacity into northern Maine from New Brunswick,
reflecting the 30% RPS). If a second New England importer is added, the HHI
drops further, to 1769.
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Figure 9: New England Renewables
Gen Mw % HHI
BHE 108 3 9
BECO 361 11 121
CMP 486 14 196
Com. Energy 230 7 49
FPL 353 10 100
Indeck 52 2 4
NU 799 24 576
USGen 468 14 196
Vt. Group 220 7 49
Other 200 299 9 13
TOTAL 3376 1313
3. Northern Maine concentration. Assuming no New England or New
Brunswick participation, northern Maine counts only four generation providers
in a position to compete for wholesale renewable sales. The HHI of 2595
indicates a high level of concentration, and a corresponding degree of market
power. However, it now appears possible that New Brunswick will submit its
transmission regime to regulatory oversight or contractual obligations
prior to the inauguration of retail choice in Maine on March 1, 2000. This would
give northern Maine some assurance of access to New England renewables imports.
The participation of one New England provider would reduce the HHI by 500
points; the addition of a second New England competitor, or New Brunswick
participation, would reduce the HHI below 1800 points. Federal authorities
consider a market with an HHI below 1800 to be moderately concentrated.
4. New England concentration. The 1313-point New England HHI shown
above indicates a moderate level of concentration, and a corresponding degree
of market power.
200 This category includes an assumed 200 mw of available NYPP imports.
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This may understate the actual degree of concentration, since a significant
amount of the New England capacity available to meet Maine's RPS is handicapped
by high production costs. 201 Such high cost capacity offers less than fully
effective price competition. 202
D. Market Power In Renewables
Under federal guidelines, HHI figures provide a basis for no more than a
presumption of market power, to be confirmed or dissipated upon consideration
of other factors which may render the creation, enhancement or facilitation of
market power more or less likely. In an analysis of the degree to which
moderate-to-high levels of market concentration in renewables in northern
Maine and New England should give rise to market power concerns, four principal
factors merit attention. These are:
- The relationship between demand and supply
- The risk of retail exclusion
- New entry prospects
- The effect of the Commission's proposed rule for implementation of
the RPS.
These points are discussed in the paragraphs below.
1. Demand and supply. Some experts take the view that there will be
a large surplus of supply over anticipated demand for renewables. If it is
sufficiently large, such a surplus could have the effect of negating horizontal
market power.
201 See F. Cummings, Impacts of Maine Portfolio Requirement on Supply and Demand
for Renewable Resources, September 21, 1998 (study commissioned by Union of
Concerned Scientists) ("Cummings") 3. Cummings estimates that as much as 1200
mw of renewable capacity falls into this high-cost category. Note that the same
also appears to be true (perhaps to a lesser degree) in northern Maine.
202 On the other hand, account should also be taken of the fact that the market
shares of market leaders NU and CMP will decline over time as the NUG contracts
they currently hold expire. However, it is believed that the effect of such
contract expirations will be minimal in the first three years of retail choice.
For example, CMP NUGs will decline by only 31.77 mw in the first three years,
out of a total of approximately 486. See CMP Response to IECG Data Request No.
2, Maine PUC Docket No. 97 -523.
-94-
Dr. Joe D. Pace, a consultant to CMP and FPL in proceedings relating to
their proposed asset transaction, calculates that Maine demand for renewables
as defined in the statute will be at the level of approximately 630-690 mw. Our
own calculations agree generally with this estimate. 203 However, Pace
overestimates the New England capacity available to meet this demand. Apparently
counting many resources which in our view do not qualify, Pace finds between
4962 and 5723 mw of available renewable capacity. 204 Our assessment, by
contrast, suggests approximately 3376 mw are available in New England. With
respect to northern Maine, it appears that approximately 118 mw of supply are
available to meet 44 mw of demand.
While noting that renewable portfolio requirements in other states in the
region "could tighten up the supply picture," Pace does not attempt to estimate
the extent of this impact, on the ground that to do so would be too speculative.
205 However, today, both Massachusetts and Connecticut have RPS provisions in
place. These two provisions differ widely from each other and from Maine's RPS.
One commentator estimates that the Massachusetts and Connecticut provisions
together are likely to result in a level of demand equivalent to Maine's RPS;
the basis for this estimate is unclear. 206 In addition, an increasing level
of consumer demand for renewables will be generated by green marketing efforts;
however, it is difficult to predict with any assurance how successful those
efforts are likely to be.
In sum, it would appear that although there is likely to be some surplus
of supply over demand for renewables in these markets, the extent and duration
of that surplus is uncertain. Accordingly, although a significant initial
mitigating effect appears likely, current estimates of oversupply cannot be
relied upon to adequately resolve long term market power concerns.
203 Pace 25; see also Cummings.
204 Pace Exhibit D.
205 Pace 27.
206 Cummings, Figure 1.
-95-
2. Vertical retail exclusion. In both northern Maine and New England,
the principal market power threat is on the vertical, rather than the horizontal
plane. This is the danger of retail exclusion.
The RPS has the effect of making participants with high renewables market
shares the gatekeepers to Maine's retail market. Any marketer wishing to enter
Maine's retail electricity market must obtain a 30% portfolio of renewables in
the wholesale market. If a group of participants with a high aggregate market
share should hoard renewable capacity, the result would be to effectively
exclude would-be entrants from the Maine retail market. This could severely
limit retail competition.
It is difficult to gauge the importance of this risk of retail exclusion
based on the current configuration of the market. Our HHI results suggest that
five New England competitors will hold an aggregate share in excess of 70% of
available renewable capacity. In northern Maine, there may be no more than five
competitors in all. In the short term, a significant surplus of renewable
supply may be sufficient to allay concerns with regard to retail exclusion. In
the longer term, in view of the potential for increased regional demand for
renewables, the threat of retail exclusion cannot be ignored.
The threat is accentuated in a market lacking liquidity and flexibility.
Renewables markets contrast sharply with other energy markets in one important
respect: they lack flexible trading mechanisms. The Commission has rejected
tradable renewable credits. 207 Moreover, ISO-NE has
207 Tradable credits would have added flexibility to the market, but would not
necessarily have prevented hoarding. The Commission's determination to use a
contract path approach, rather than tradable credits, was based in part on its
conclusion that consistency across New England was important. Other New England
states favor contract path tracking.
-96-
no plans to play any role in administering a regional renewables spot market.
While there may be some prospect that private renewables exchanges will arise
(as they have in California), 208 until they do, entrants into Maine retail
markets will have to satisfy their 30% RPS requirement on the bilateral contract
market. Some of these contracts are likely to be long term undertakings. A
problem of availability could arise, ossifying the wholesale market.
Worse yet, exclusive reliance on bilateral contracts as a trading mechanism
could cause the renewables market to evolve in an anticompetitive direction,
concentrating even greater control in the hands of a few dominant players, and
according participants with high market share the ability to select or veto
their retail competitors, and to control the levels and prices at which they are
able to compete.
3. New entry prospects. Most planned new entry in New England is
gas-fired generation, which, broadly speaking, is not renewable.209 No new entry
is expected in northern Maine. Although the Massachusetts and Connecticut RPS
laws contain provisions designed to encourage new renewable development, it is
likely that the scale of such development in the short and medium term will be
modest. The Maine statute will not have the effect of encouraging new entry in
the renewables market. 210 Certainly, new entry should not be counted on
to play a major role in mitigating market power in renewables markets.
4. Effect of proposed renewables rule. Conscious of the pitfalls
facing renewables markets, the Commission has endeavored to craft a rule for
implementation of the
208 See The APX Green Power Market,
http://www.energy-exchange.com/html/apx_green.htm. In a telephone conversation
with the Department on July 22, 1998, Jack Ellis, executive vice president of
APX, indicated interest in opening a private energy exchange in New England, but
expressed concern that New England may not be receptive to such an initiative.
In any event, the task of private exchanges will be complicated by the
divergence of state RPS requirements in the region.
209 In fact, new gas-fired generation does not qualify in Maine (grandfathered
gas-fired cogeneration does); however, gas-powered fuel cells do qualify in both
Massachusetts and Maine.
210 Cummings and Biewald agree on this point.
-97-
RPS which, as far as possible within the confines of the law as enacted, can
assist in mitigating market power. Specifically, the rule measures compliance
over a twelve-month period. In addition, it provides for a further one-year cure
period, allowing a competitive provider additional time to make up any
deficiency. As an encouragement to new entry, the cure period may be extended
when the provider is able to show that it possesses an entitlement to energy
from a renewable facility that will be in service within two years and whose
output will allow for compliance. In addition, the Commission reserves the
discretion to sanction noncompliance by means of a required "optional payment,"
in lieu of license revocation. The payment, based on the per-kilowatt hour cost
of compliance, would go to a fund for renewable resource r&d. Finally, the
Commission retains the ability to waive sanctions altogether if it finds that
the "provider made good faith efforts but could not reasonably satisfy the
portfolio requirement due to market conditions." 211
These regulatory provisions allow the Commission the flexibility to address
the effects of an exercise of market power that may occur in an individual case.
They do not, however, represent an adequate long term solution for retail market
exclusion, in the event this should become a systemic market power problem.
E. Remedies for Market Power in Renewables
It is probable that the moderate to high levels of concentration and
market power in northern Maine and New England renewables markets are adequately
mitigated by the current condition of oversupply. However, as growing demand
takes up the slack of oversupply, market power may begin to pose a serious
threat. The greatest risk is in the vertical dimension: the possibility that
overconcentration and inflexibility in wholesale markets for renewables will
have
211 Renewable Rule paragraph 6. In order to be eligible for the cure period, the
provider must show at least 20% of sales served by renewables.
-98-
the effect of constricting entry into, and competition within, Maine retail
energy markets generally. However, as supply tightens, horizontal market power
could also threaten competition in northern Maine, or in New England.
In view of this analysis, we recommend a limited legislative measure which
would permit the Commission to take appropriate action in the event that the
market power problems which we discern begin to result in actual disruption of
markets. Specifically, the Legislature should empower the Commission to suspend
or reduce the percentage of the RPS in any section of the State on market power
grounds. In the meantime, the Commission will explore the options for
development of a publicly or privately administered renewables spot market or
exchange, and will investigate the possibility of setting up a limited bulletin
board or clearinghouse system to provide an interim mechanism for trading
renewables as defined in the Maine RPS.
Another important remedial measure is open to the Commission without the
need of legislation: to require piecemeal sales of NUGs in the context of
upcoming proceedings. The analysis offered above suggests that this option
merits consideration. 212
F. Recommendation
The Legislature should empower the Commission to suspend, or reduce the
percentage of, the RPS in any section of the State, on market power grounds.
212 Currently, the CMP NUGs represent the second largest block of renewable
capacity in the market. Requiring sale in two segments would reduce the HHI by
an estimated 100 points. Piecemeal sale would also reduce the risk of retail
exclusion.
-99-
VII. CONCLUSION
Maine's electric industry restructuring initiative offers significant
potential benefits: lower consumer prices for electricity, and the more
generalized economic benefits which flow from competitive energy prices.
However, vertical and horizontal market power pose a serious threat
to the success of this endeavor. Unless the threat is effectively countered, the
potential benefits of restructuring could be reduced or lost.
This report analyzes the nature of the market power threat, and considers
available remedies. Because Maine is part of regional, and, to some extent,
international, electricity markets, the jurisdictional ability of the Maine
Legislature to provide adequate remedies for market power in all its aspects,
and thereby ensure the success of restructuring, is limited. Where state
jurisdiction exists, we recommend certain statutory adjustments to enhance
protections against market power abuse. To the extent that market power problems
are subject to federal or Canadian jurisdiction, the Commission and the
Department are committed to, and have been active in, advocating for open,
competitive markets and additional protections against market power.
In this report, we recommend adjustments to the restructuring statute as
follows:
- the code of conduct and market share limitation governing marketing by
transmission & distribution ("t&d") company affiliates should be
reinforced as a means to provide additional protection against vertical
market power
- the Commission should be empowered to assess against the t&d and its
affiliate the cost of enforcement resulting from violations of the code
of conduct and market share limitation
- the Commission should be empowered to impose wholesale rate regulation
on market power grounds (a) in a load pocket which arises in all hours
for more than 48 hours; and (b) in northern Maine
-100-
- northern Maine t&d companies should be authorized to enter contracts with
New Brunswick Power Corporation ("NBP") for the purchase of back-up
power, needed ancillary services and transmission services
- the Commission should be empowered to require northern Maine t&ds to pass
back-up power, ancillary services and transmission services purchased
from NBP through to their customers at cost
- the Commission should be empowered to suspend or reduce the Renewable
Portfolio Standard in any section of the State on market power grounds.
Electricity markets in Maine, or of which Maine forms a part, are evolving
rapidly. As restructuring moves forward, the Commission and the Department may
have occasion to offer additional legislative recommendations. In particular,
we plan to consider:
- whether experience with the statutory compromise permitting t&d
affiliates to engage in retail marketing warrants further legislative
adjustment
- whether specific legislative initiatives should be proposed to promote
demand elasticity as a means to combat market power
- whether legislation is necessary to facilitate the emergence of an
appropriate bulk power administration system for northern Maine
- whether legislation is necessary to facilitate the development of
specific transmission or generation projects as a means to mitigate
market power.
- whether legislation to provide for civil remedies for an exercise of
market power in a load pocket is advisable.
While not without its risks and challenges, electric restructuring has the
potential to bring substantial benefits to Maine consumers and the Maine
economy. The Commission and the Department look forward to working with the
Joint Standing Committee on Utilities and Energy, and with the Legislature as
a whole, to do all that we can to make this promise a reality for the people of
our State.
* * * * * * * * * * * *
Exhibit 99(v)
85 FERC p. 61,412
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
OPINION NO. 434
Maine Public Service Company ) Docket No. ER95-836-000
OPINION AND ORDER AFFIRMING IN PART AND
REVERSING IN PART INITIAL DECISION
Issued: December 22, 1998
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Maine Public Service Company ) Docket No. ER95-836-000
OPINION NO. 434
APPEARANCES
Michael E. Small, Wendy N. Reed, and James T. McManus for Maine
Public Service Company.
George M. Williams, Jr., Robert C. Platt, and Rita L. Wecker for
Wholesale Customers.
Raymond W. Hepper and Thomas C. Sturtevant, Jr. for Central Maine
Power Company.
Linda L. Walsh and JoAnn Scott for the Trial Staff of the Federal
Energy Regulatory Commission.
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: James J. Hoecker, Chairman;
Vicky A. Bailey, William L. Massey,
Linda Breathitt, and Curt Hebert, Jr.
Maine Public Service Company ) Docket No. ER95-836-000
OPINION NO. 434
OPINION AND ORDER AFFIRMING IN PART AND
REVERSING IN PART INITIAL DECISION
(Issued December 22, 1998)
I. Introduction
This proceeding is before the Commission on exceptions to an
Initial Decision. 1/ It involves rate design issues related to
firm and nonfirm point-to-point and network transmission services
as well as ancillary services provided under Maine Public Service
Company's (Maine Public) open access transmission tariff. In
this opinion and order, we affirm in part and reverse in part the
Initial Decision.
II. Background
On March 31, 1995, Maine Public filed an open access
transmission tariff that offers firm and nonfirm point-to-point
and network transmission services as well as ancillary services.
2/ The Commission's order, among other things, accepted the
proposed transmission tariff for filing, suspended it for a
nominal period to become effective June 1, 1995, subject to
1/ Maine Public Service Company, 74 FERC P.63,011
(1996)(Initial Decision).
2/ By order issued February 2, 1996, the Commission
consolidated Docket No. ER95-836-000 with Docket Nos. ER96-
370-000 and ER96-561-000, which concerned Maine Public's
unexecuted service agreement with Houlton Water Company and
revisions to its open access transmission tariff. Maine
Public Service Company, 74 FERC P.61,098 (1996). However,
as the result of a settlement agreement approved by the
Commission, Docket Nos. ER96-370-000 and ER96-561-000 were
terminated by letter-order issued July 18, 1996. Maine
Public Service Company, 76 FERC P.61,060 (1996).
Docket No. ER95-836-000 -2-
refund, and set it for hearing. 3/ Subsequently, on
September 27, 1995, the Commission issued an order which
effectively removed all non-rate terms and conditions issues
from this proceeding. 4/ While this proceeding was pending, the
Commission issued its final rule in Order No. 888. 5/
III. Litigated Issues
The following issues were litigated before, and decided by
the presiding judge: (a) whether, in developing transmission
rates, Maine Public should use a levelized fixed charge
methodology using original undepreciated plant cost (gross
plant), or a non-levelized methodology using depreciated plant
cost (net plant); (b) whether Maine Public should be allowed to
charge a one mill per kWh adder for difficult to quantify costs
in rates for short term (less than one year) firm and nonfirm
point-to-point transmission service; (c) whether the demands
associated with three non-tariff firm wheeling contracts should
be added to Maine Public's demand in developing a system-wide
transmission rate or whether a revenue credit approach should be
used to develop Maine Public's revenue requirement and system-
wide transmission rate; (d) whether the cost of generator step-up
transformers (GSUs) should be included in transmission rates; (e)
whether Maine Public should include the cost of 34.5 kV
facilities in transmission rates; (f) whether transmission
customers must purchase all ancillary services from Maine Public
in conjunction with the purchase of transmission service; and (g)
the appropriate bandwidth relating to unscheduled energy service.
The Commission's Trial Staff (Trial Staff), Maine Public,
and Wholesale Customers (consisting of Houlton Water Company, Van
Buren Light and Power District, and Eastern Maine Electric
Cooperative), filed briefs on and opposing exceptions.
3/ Maine Public Service Company, 71 FERC P. 61,249 (1995), order
on reh'g, 81 FERC P.61,309 (1997).
4/ American Electric Power Service Corporation, et al., 71 FERC
P.61,393, order on reh'g, 72 FERC P.61,287 at 62,238 (1995),
reh'g denied, 74 FERC P.61,013 (1996).
5/ See Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Service by Public Utilities;
Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities, Order No. 888, 61 Fed. Reg. 21,540
(May 10, 1996), FERC Stats. & Regs. P.31,036 (1996), order
on reh'g, Order No. 888-A, 62 Fed. Reg. 12,274 (March 14,
1997), FERC Stats. & Regs. P.31,048 (1997), order on reh'g,
Order No. 888-B, 81 FERC P.61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC P.61,046 (1998) (Order No. 888).
Docket No. ER95-836-000 -3-
IV. Summary Affirmance of Initial Decision
The Commission summarily affirms the Initial Decision on the
following issues: (a) rejection of the one mill per kWh adder;
6/ (b) inclusion of non-tariff transmission demands in the rate
denominator; 7/ and (c) rejection of Maine Public's proposal to
require transmission customers to purchase all ancillary services
from Maine Public. 8/ We find that the presiding judge properly
6/ 74 FERC at 65,018.
7/ Id. at 65,019-20. The presiding judge's determination is in
accord with Commission precedent. See Pennsylvania Power
Company, Opinion No. 211, 26 FERC 61,354 at 61,781, order
on reh'g, Opinion No. 211-A, 27 FERC 61,290 (1984). See
also Arizona Public Service Company, Opinion No. 137, 18
FERC 61,197 at 61,394, order on reh'g, Opinion No. 137-A,
20 FERC 61,407 (1982), remanded on other grounds,
Electrical Dist. No. 1 v. FERC, 774 F.2d 490 (D.C. Cir.
1985); Public Service Company of New Mexico, Opinion No.
146, 20 FERC 61,290 at 61,546-48 (1982), order on reh'g,
21 FERC 61,334 (1983); Boston Edison Company, Opinion No.
53, 8 FERC 61,077 at 61,283, reh'g denied, Opinion No. 53-
A, 9 FERC 61,002 (1979).
8/ 74 FERC at 65,019-20 (the presiding judge concluded that
transmission customers must purchase so-called Var Support
and System Control/Load Dispatch ancillary services from
Maine Public, but that transmission customers may purchase
so-called load following and Supplemental Operating Reserves
ancillary services from others).
We note that, subsequent to the issuance of the Initial
Decision, the Commission, in Order No. 888, addressed this
issue and adopted requirements fully consistent with the
findings of the presiding judge on this issue.
Specifically, in Order No. 888, the Commission established
that the transmission provider must provide and the
transmission customer must purchase from the transmission
provider: (1) Scheduling, System Control and Dispatch
Service (referred to as System Control/Load Dispatch in this
proceeding) and (2) Reactive Supply and Voltage Control from
Generation Sources Service (referred to as Var Support in
this proceeding), subject to conditions set out in Order No.
888. The Commission further determined that the
transmission provider must offer to the transmission
customer, but the transmission customer need not take, the
remaining four services , including Regulation and Frequency
Response Service (referred to as load following in this
proceeding); Energy Imbalance Service; Operating Reserve -
(continued...)
Docket No. ER95-836-000 -4-
decided these issues and the arguments on exceptions have failed
to persuade us that the Initial Decision erred or that additional
discussion is necessary.
The Commission further summarily affirms the presiding
judge's findings that Maine Public can require an unscheduled
energy charge 9/ for point-to-point and network transmission
service with a bandwidth deviation of +/- 1.5 percent. However,
we affirm in part and reverse in part the judge's adoption of a 1
MW minimum for the unscheduled energy service. We note that the
instant proceeding was made subject to the outcome of the Order
No. 888 proceeding. 10/ In Order No. 888-A, the Commission
raised the minimum energy imbalance from 1 MW to 2 MW per hour.
11/ Therefore, we will affirm the presiding judge's decision
with respect to the 1 MW minimum from the period of the effective
date of the proposed rates (June 1, 1995) until the effective
date of our decision in Order No. 888-A (May 13, 1997). For the
period after the effective date of Order No. 888-A, however, we
will adopt the 2 MW minimum as required in Order No. 888-A.
V. Issues for Discussion
A. Fixed Charge Rate Design - Levelized vs. Non-Levelized
At issue in this proceeding is whether a non-levelized net
plant or levelized gross plant approach is appropriate for
developing Maine Public's rates for open access transmission
service. In general, under the non-levelized net plant method,
the original cost of a utility's facilities is reduced
incrementally, through the depreciation component of rates, over
the life of those facilities, and a rate of return is applied to
the remaining cost balance of the facilities (i.e. the net
plant). Conversely, under a levelized rate method based on gross
8/ (...continued)
Spinning Reserve Service; and Operating Reserve -
Supplemental Reserve Service (referred to as Supplemental
Operating Reserves in this proceeding). Order No. 888, FERC
Stats. & Regs. at 31,703-08, 31,715-17.
9/ Id. at 65,020-21. Throughout this proceeding the parties
used the term "unscheduled energy charge." In Order No.
888, the Commission adopted the term Energy Imbalance
Service for this service. Order No. 888, FERC Stats. &
Regs. at 31,708. Because the term "unscheduled energy
charge" has been used extensively in the record, we will
continue to use this term herein.
10/ Order No. 888, FERC Stats. & Regs. at 31,768.
11/ Order No. 888-A, FERC Stats. & Regs. at 30,232-33.
Docket No. ER95-836-000 -5-
plant balances, the lifetime capital costs (depreciation and
return) associated with a utility's assets are spread evenly over
the life of those assets and the capital costs are recovered by
applying a fixed carrying charge percentage to the original
(gross) cost of these assets.
Initial Decision
The presiding judge rejected Maine Public's proposal to
utilize a levelized gross plant methodology, and found, instead,
that Maine Public should continue to use a non-levelized net
plant methodology in developing its transmission rates. 12/
Noting that Maine Public's system is relatively old and was
approximately 55 percent depreciated in 1994, the presiding judge
determined that the change to a levelized gross plant methodology
would result in long-time customers "double-paying" for using
these depreciated facilities. The presiding judge found that
Commission cases, including Southern California Edison Company,
Opinion No. 341, 50 FERC 61,138 (1990), and the Commission's
Open Access NOPR, 13/ do not mandate the use of levelized
methodologies in all future ratemaking proceedings. The
presiding judge observed that these cases do not involve a change
in rate methodologies, i.e., switching from a non-levelized
methodology to a levelized methodology, but, instead, involved a
continuation of previously-existing levelized rate methodologies.
In addition, the presiding judge found that since Maine Public is
using the same facilities to provide the proposed transmission
service for the same customers, no "new service" 14/ is involved
which would warrant a change in rate methodologies. Finally, the
presiding judge rejected Trial Staff's suggestion that the
levelized methodology be applied to Maine Public's existing,
depreciated system because there was no showing that Maine Public
expected new transmission customers. Accordingly, the presiding
judge concluded that the non-levelized net plant methodology is
12/ 74 FERC at 65,017-18.
13/ Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Service by Public Utilities and
Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities, Notice of Proposed Rulemaking and
Supplemental Notice of Proposed Rulemaking, 60 Fed Reg.
17,662 (April 7, 1995), FERC Stats. & Regs. P.32,514 (1995)
(Open Access NOPR).
14/ The Commission defines a new service by looking at the
fundamental characteristics of the service. See, e.g.,
Southwestern Public Service Company, 72 FERC P.61,104 at
61,559 (1995), reh'g pending.
Docket No. ER95-836-000 -6-
the most appropriate rate structure for transmission service
under Maine Public's open access transmission tariff. 15/
Exceptions
Maine Public, on exceptions, argues that its levelized rate
methodology is: consistent with Commission policy; best fits a
generic tariff; is supported by the actual operation of its
transmission facilities; promotes a level playing field;
satisfies comparability; will not overrecover costs; and
promotes rate stability. 16/ Maine Public maintains that its
prior use of a non-levelized methodology does not preclude a
switch to a levelized methodology. Maine Public argues that the
use of a levelized methodology will not result in an overrecovery
of costs, contending that a levelized methodology applied to
original cost produces a reasonable result at any point during
the life of the asset. In addition, Maine Public argues that the
presiding judge erred in relying upon the age of Maine Public's
facilities as a basis to reject the proposed levelized rate
methodology. 17/
Wholesale Customers and Trial Staff oppose Maine Public's
exceptions. They argue that Maine Public's levelized rate
methodology would result in overrecovery; there is no showing
that a levelized rate methodology would promote rate stability;
there is no foreseeable likelihood of substantial new
transmission facilities; and the imposition of higher, levelized
rates on open access transmission would be anticompetitive.
Additionally, Wholesale Customers argue that Opinion No. 341 does
not sanction the use of a levelized methodology because it did
not involve a switch to a levelized approach. 18/
Discussion
We affirm the presiding judge on this issue. Maine Public
traditionally has developed transmission rates using a non-
levelized net plant methodology. In its open access transmission
tariff, Maine Public proposed transmission rates based upon the
levelized gross plant methodology. As the Commission found in
Kentucky Utilities Company, 85 FERC P.61,274 at ____, slip op. at
7 (1998)(Kentucky Utilities), this switching of methodologies,
from non-levelized net plant to levelized gross plant, opens the
15/ 74 FERC at 65,017-18.
16/ Maine Public Brief on Exceptions at 10-28.
17/ Id. at 28-39.
18/ Wholesale Customers Brief Opposing Exceptions at 6-16;
Trial Staff Brief Opposing Exceptions at 7-32.
Docket No. ER95-836-000 -7-
door to the potential overrecovery of costs. Switching to a
levelized gross plant methodology at this time will allow Maine
Public to recover anew depreciation expense that it has already
recovered, and therefore overrecover its transmission revenue
requirement.
Maine Public claims that its levelized gross plant
methodology will not overrecover costs because, under either a
levelized or non-levelized approach, the utility recovers, on a
net present value basis, the identical capital costs, i.e.
depreciation and return on rate base. 19/ As long as either
method is consistently used throughout the life of an asset,
Maine Public is correct. However, in this case, Maine Public
proposes to switch methodologies mid-stream. As we noted in
Kentucky Utilities, this produces an unreasonable result. In
Kentucky Utilities, 85 FERC at _____, slip op. at 7-8, the
Commission determined that past contributions to the fixed costs
of the utility's transmission system are relevant because a large
portion of the costs of that system have already been recovered.
A similar situation is present here. Maine Public's transmission
facilities are over 50 percent depreciated with no significant
transmission additions or upgrades planned. Thus, permitting
Maine Public to switch to a levelized gross plant methodology at
this time would potentially result in Maine Public recovering
more than the lifetime revenue requirement associated with its
existing transmission facilities.
Furthermore, as we observed in Kentucky Utilities, 85 FERC
at _____, slip op. at 8, allowing Maine Public to switch to a
levelized gross plant methodology at this late date might
discourage a wholesale requirements customer that is now paying a
bundled, non-levelized rate from seeking cheaper off-system power
because of the significantly higher levelized gross plant
transmission rate it would have to pay as a customer taking
unbundled service. 20/ This result "would hinder the very
19/ Maine Public Brief on Exceptions at 25.
20/ The current point-to-point transmission rate based on the
non-levelized net plant methodology is $13.90/kW/year. Tr.
336. When switching to the levelized gross plant
methodology, the point-to-point tariff rate substantially
increases to $31.63 (the base rate for point-to-point
service is $23.22/kW/year, and, with ancillary services,
would be $31.63/kW/year). The network tariff rate would be
$35.69/kW/year. Maine Public Ex. 3, Schedules 2-6. As
Maine Public acknowledges, the increase in rates is due
solely to the change in methodology, not increased costs.
Tr.341.
Docket No. ER95-836-000 -8-
competition that Order No. 888 and [the Commission's Transmission
Pricing] Policy Statement were intended to promote." 21/
Moreover, as we also observed in Kentucky Utilities, 85 FERC
at _____, slip op. at 8-9, reliance on Opinion No. 341 in support
of Maine Public's position is not persuasive because, in contrast
to the situation before us now, that utility historically had
been using the levelized gross plant method to design its
transmission rate and was not proposing a change. 22/ In fact,
in Opinion No. 341, we rejected a proposed switching of
methodologies because in those circumstances it would lead to an
unreasonable result. In addition, we also found that a switch
might require adjustments to take account of factors related to
the differing cost recovery methods (e.g., depreciation). This
reasoning applies in this proceeding as well.
Therefore, we reject Maine Public's proposal to develop its
open access transmission tariff rates using a levelized gross
plant methodology, and we will require Maine Public to
recalculate its tariff rates based on a non-levelized net plant
methodology.
B. Inclusion of the Cost of GSUs in the Calculation of
Rates
Initial Decision
The presiding judge concluded that Maine Public properly
included the cost of GSUs 23/ in the transmission rates. The
presiding judge found that GSUs cannot easily be allocated to
specific portions of Maine Public's transmission system or to
specific services provided by the transmission system. However,
the presiding judge determined that GSUs traditionally have been
21/ Kentucky Utilities, 85 FERC at _____, slip op. at 8; see
Order No. 888, FERC Stats. & Regs. at 31,635-36, 31,638-52;
Inquiry Concerning the Commission's Pricing Policy for
Transmission Services Provided by Public Utilities Under the
Federal Power Act, 59 Fed. Reg. 55,031 (November 3, 1994),
FERC Stats. & Regs. P.31,005 at 31,141-44 (1994), order on
reconsid., 71 FERC P.61,195 (1995).
22/ In Opinion No. 341, intervenors were seeking a change in
rate design from a levelized gross plant to a levelized net
plant methodology. 50 FERC at 61,409-12.
23/ A GSU is an electrical device that transforms power from a
lower voltage to a higher voltage. The GSUs in question in
this proceeding are those which step-up lower voltages at
the generation level to higher voltages at the transmission
level.
Docket No. ER95-836-000 -9-
classified as performing a transmission function, and are an
"integral" part of the transmission network because they maintain
voltage levels on the entire system. 24/
Exceptions
Trial Staff, on exceptions, argues that, to the extent GSUs
enhance generators' ability to reach the transmission system,
Maine Public should exclude their cost from its transmission
rates, and allocate them instead to the generators they support.
Trial Staff also argues, to the extent Maine Public uses the GSUs
to transmit reactive power, GSU costs should be allocated to a
separate reactive power charge. Trial Staff argues that Maine
Public's failure to precisely identify and allocate the costs of
its GSUs does not justify recovery of all GSU costs in
transmission rates. 25/
Maine Public opposes Trial Staff's exceptions, arguing that,
under Commission policy, GSUs are considered transmission-related
rather than generation-related. 26/
Discussion
We reverse the presiding judge on this issue. As we noted
in Kentucky Utilities, 85 FERC at _____, slip op. at 18-19, the
Commission, in the past, has functionalized the cost of GSUs to
transmission, and allowed the utility to recover those costs by
rolling them into the transmission rates. However, we note that
substantial changes have occurred in the electric industry,
particularly given Order No. 888's requirement to unbundle
transmission and wholesale generation services and the resultant
increase in transmission-only service. In light of these facts,
we recognized in Kentucky Utilities the need to reexamine our
policy on the proper functionalization and recovery of costs
associated with GSUs to ensure that unbundled service customers
are paying only their appropriate share of the cost of the
services they use.
Reexamining GSU costs in this case shows that the costs of a
GSU should be directly assigned to its related generating unit,
not rolled into transmission rates. As we noted in Kentucky
Utilities, 85 FERC at _____, slip op. at 19-20, this result is
appropriate because, given the unbundling of generation and
transmission, GSUs serve two functions: one in support of
24/ 74 FERC at 65,018.
25/ Trial Staff Brief on Exceptions at 2-8.
26/ Maine Public Brief Opposing Exceptions at 44-49.
Docket No. ER95-836-000 -10-
generation 27/ and another in support of ancillary services
(e.g., Operating Reserve, Regulation and Frequency Response
Service, Reactive Supply and Voltage Control). We found, in
Kentucky Utilities, 85 FERC at _____, slip op. at 20, that since
GSUs are used in the provision of both generation and ancillary
services, the costs of those facilities should be charged to the
customers using the GSUs. By directly assigning each GSU to the
generator to which it is connected, GSU costs will be recovered
through the power sales and/or ancillary service rates of the
entity selling power and/or ancillary services from that
generator, depending on the use of the generator. 28/ Finally,
as we stated in Kentucky Utilities, 85 FERC at _____, slip op. at
21, ". . . direct assignment of GSU costs is also consistent with
our established practice of directly assigning interconnection
costs. . . . GSUs are not part of a utility's integrated
transmission grid and should not be charged to transmission-only
customers (except for ancillary services). Instead, GSU costs
are incurred because of the installation of a generating unit and
should be assigned directly to that unit, so that customers
taking service from that unit pay the appropriate costs."
In conclusion, we recognize that given the unbundling of
generation and transmission, GSUs serve two functions, in support
of both unbundled generation and unbundled ancillary services,
and therefore, GSU costs should not be rolled into unbundled
transmission rates. Rather, their costs should instead be
assigned to the generators to which they are connected to more
accurately allocate those costs to the customers using those
facilities (i.e., to the customers buying power or ancillary
services).
C. 34.5 kV Facilities
Initial Decision
Maine Public's transmission rate includes the cost of three
low-voltage, 34.5 kV facilities. The presiding judge found that
these facilities serve a distribution function and are not
27/ For example, GSUs support the generation function by (1)
raising power to higher voltages that make it cheaper to
transmit, (2) enabling utilities to install generators that
are sized efficiently so they can serve loads in a more
economical manner, and (3) leading to the more efficient
siting of generation facilities.
28/ Direct assignment of a utility's GSUs is also consistent
with the method in which Maine Public intends to treat the
GSU of a customer connecting new generation to its system.
Tr. at 251.
Docket No. ER95-836-000 -11-
properly included in Maine Public's cost of transmission. 29/
The presiding judge rejected Maine Public's argument that the
three 34.5 kV facilities are "integrated" into its transmission
system because the facilities can be upgraded in the future to be
used by transmission customers. The presiding judge concluded
that the facilities should be classified on the basis of what
function they serve now, not what function they may serve in the
future.
Exceptions
Maine Public, on exceptions, argues that the presiding judge
erred in finding that the three 34.5 kV facilities serve a
distribution, and not a transmission, function, and, hence, are
not entitled to be rolled into the calculation of the
transmission rate. Maine Public argues that the 34.5 kV
facilities are part of its integrated system which benefits
transmission. Specifically, Maine Public maintains, it can
upgrade, or "loop" the 34.5 kV facilities to provide increased
reliability or integrate those facilities into the overall
transmission system, and has done so in the past. Maine Public
also argues that, in several prior cases, the Commission has
considered 34.5 kV facilities to be integrated transmission
facilities and accorded them rolled-in treatment. 30/
Wholesale Customers oppose Maine Public's exceptions,
arguing that the cost of the three 34.5 kV facilities should only
be included in transmission when they are actually integrated.
Wholesale Customers explain that these lower voltage facilities
are "integrated" when, in addition to being connected with higher
voltage facilities, they are themselves interconnected and
designed to operate in parallel. Wholesale Customers state that
this is referred to as "looping;" that is, the lower voltage
facilities form parallel paths for electric energy with the
higher voltage transmission facilities. It is the existence of
two or more parallel transmission paths from sources of power to
users of power that establishes integration. Given this
definition of integrated facilities, Wholesale Customers argue
29/ 74 FERC at 65,018-19. A fourth 34.5 kV line is non-radial
in nature and is integrated into the transmission system,
and is properly included in the transmission rate. Id. at
65,019.
30/ Maine Public Brief on Exceptions at 45-51, citing, inter
alia, Niagara Mohawk Power Corporation, Opinion No. 296,
42 FERC P.61,143 (1988) (Niagara Mohawk) and Utah Power
& Light Company, 28 FERC P.61,088 (1984) (Utah P&L).
Docket No. ER95-836-000 -12-
that Maine Public's 34.5 kV facilities are not integrated. 31/
According to Wholesale Customers, it is undisputed that the 34.5
kV facilities in question are radial (i.e., non-looped) lines,
devoted entirely to feeding retail, distribution-level customers;
they carry no transmission flows, and no transmission customer is
served at this voltage level. Wholesale Customers state that,
until such time as Maine Public upgrades its lines, the 34.5 kV
radial facilities are properly classified as distribution, and
the costs of those facilities should be excluded from
transmission rates. 32/
Discussion
We affirm the presiding judge on this issue. In the cases
cited by Maine Public, the Commission found that sufficient
evidence had been presented to demonstrate that the facilities in
question were part of an integrated transmission system and that,
therefore, roll-in was appropriate. Here, there is no evidence,
aside from a general description of the three 34.5 kV facilities,
to demonstrate that these facilities were integrated into its
transmission system.
In Otter Tail Power Company, Opinion No. 93, 12 FERC
p. 61,169 at 61,420 (1980),for example, the Commission stated that
"while the rolled-in approach has generally been followed, the
Commission has recognized that exceptions should be made in some
cases and has held that it would continue to review the facts of
each case to determine the applicability of the rolled-in
approach." In Sierra Pacific Power Co. v. FERC, the court
defined integration as follows:
Lower voltage transmission facilities are
"integrated" . . . when, in addition to being
connected with higher voltage facilities, the
lower voltage facilities are themselves
interconnected and designed to operate in
parallel. This is also referred to as
"looping," that is, the lower voltage
transmission facilities form parallel paths
for electric energy with the higher voltage
transmission facilities. The existence of
two or more parallel transmission paths from
31/ Wholesale Customers Brief Opposing Exceptions at 19, citing
Sierra Pacific Power Co. v. FERC, 793 F.2d 1086 at 1088 (9th
Cir. 1986).
32/ Id. at 16-20.
Docket No. ER95-836-000 -13-
sources of power to receiving points
establishes integration. [33/]
It is undisputed in this record that Maine Public's three 34.5 kV
lines at issue are radial lines that are not currently looped.
34/ Based upon this record evidence, we determine that these
radial, non-looped lines do not operate in parallel with Maine
Public's transmission system and therefore are not integrated
with the transmission system. Rather, as correctly determined by
the presiding judge, the three 34.5 kV lines perform only a
distribution function. 35/ On the basis of this evidence, we
cannot permit Maine Public to include the costs of the three 34.5
kV lines in its transmission rates.
The Commission orders:
(A) The Initial Decision is hereby affirmed in part and
reversed in part, as discussed in the body of this order.
(B) Maine Public is hereby directed to submit a compliance
filing as discussed in the body of this order within 60 days of
the date of issuance of this order. However, if a request for
rehearing is filed, Maine Public shall make its compliance filing
within 30 days of the date the Commission disposes of the request
for rehearing.
(C) Within 30 days of the date of acceptance of the
compliance filing, Maine Public shall make refunds together with
interest calculated pursuant to 18 C.F.R. 35.19a (1998).
Within 15 days of the date of payment of refunds, Maine Public
33/ 793 F.2d 1086, 1088 (9th Cir. 1986); accord, Maine Public
Service Company v. FERC, 964 F.2d 5, 8-9 (D.C. Cir. 1992).
34/ Tr. at 228; Ex. WC-1 at 18-19. See also Ex. MPS-8 at 19-20.
35/ The remaining 34.5 kV line is properly included in the
transmission rate since it is a non-radial line and
integrated into Maine Public's transmission system.
Docket No. ER95-836-000 -14-
shall file a report showing the computation of refunds and
interest paid. A copy of the refund report shall also be sent to
the affected state commissions.
By the Commission.
( S E A L )
/s/ Linwood A. Watson, Jr.
Linwood A. Watson, Jr.,
Acting Secretary.
[ARTICLE] UT
[MULTIPLIER] 1,000
<TABLE>
<S> <C>
[PERIOD-TYPE] 12-MOS
[FISCAL-YEAR-END] DEC-31-1998
[PERIOD-END] DEC-31-1998
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[OTHER-INCOME-NET] 415
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[NET-INCOME] 2253
[PREFERRED-STOCK-DIVIDENDS] 0
[EARNINGS-AVAILABLE-FOR-COMM] 2253
[COMMON-STOCK-DIVIDENDS] 1617
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[CASH-FLOW-OPERATIONS] (2147)
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