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, 1999 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 21, 2000: $ 27,925,969.
The number of shares outstanding of each of the issuer's classes of common stock as of March 21, 2000.
Common Stock, $7.00 par value - 1,607,250 shares
DOCUMENTS INCORPORATED BY REFERENCE
1. The Company's 1999 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, 1999, which is the end of the fiscal year covered by this report, is incorporated by
reference into Part III.
(Page 1 of 46 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 "Canadian Subsidiary") was incorporated in 1903 under the laws of the
Province of New Brunswick, Canada. Energy Atlantic, LLC (EA), the Company's
unregulated marketing subsidiary, formally began operations in January, 1999.
The Company, until the generating assets were sold on June 8, 1999, produced
electric energy, and currently engages in the 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 Canadian Subsidiary was primarily a hydro-electric generating company. It
owned and operated the Tinker hydro plant in New Brunswick, Canada until June 8, 1999,
when these assets were sold to WPS-PDI. Prior to the generating asset sale, the Canadian
Subsidiary sold to the Company the energy not needed to supply its wholesale New
Brunswick customer. During 1999, sales to the Company amounted to 65,333 MWH out
of the 78,109 MWH generated for sale at Tinker.
See Items 3(a) and (b) of the "Legal Proceedings" section of this Form 10-K for
further discussion of Maine's electric utility deregulation law and the sale of the
Company's generating assets.
EA participated in the wholesale power market during 1999 and will be selling
energy in the retail market when the Maine retail electrical industry opens for competition
on March 1, 2000.
The Company, the Canadian Subsidiary and EA required 942,974 MWH to serve
all customers for the twelve months ended December 31, 1999. The following table sets
forth the sources of their power requirements in 1999:
1999 Megawatt-hours Generated
Sources of Power or Purchased
Net Generation:
Hydro 81,543
Steam 28,783
Diesel (443)
Total 109,883
Purchases:
Fossil Fuel Generated 475,858
Biomass Generated 359,353
Total 835,211
Inadvertent Received (2,120)
Total System 942,974
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. 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 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.
Financial Information about Foreign and Domestic Operations
Financial Information Relating
To Foreign and Domestic Operations
(In Thousands of U.S. Dollars)
1999 1998 1997
Revenues from
Unaffiliated Customers:
Parent-United States 58,677 55,958 54,291
Subsidiary-United States 8,429 - -
Total Domestic 67,106 55,958 54,291
Subsidiary-Canada 350 669 781
Intercompany Revenues:
Parent-United States 323 644 728
Subsidiary-United States 311 - -
Total Domestic 634 644 728
Subsidiary-Canada 1,027 1,748 1,672
Operating Income (Loss):
Parent-United States 7,308 5,785 567
Subsidiary-United States (335) - -
Total Domestic 6,973 5,785 567
Subsidiary-Canada 104 380 344
Net Income (Loss)
Parent-United States 3,811 1,886 (2,521)
Subsidiary-United States (354) - -
Total Domestic 3,457 1,886 (2,521)
Subsidiary-Canada 549 367 344
Identifiable Assets:
Parent-United States 160,782 157,476 156,207
Subsidiary-United States 1,445 - -
Total Domestic 162,227 157,476 156,207
Subsidiary-Canada 9,321 6,820 7,274
The identifiable assets, by company, are those assets used in each company's
operations, excluding intercompany receivables and investments.
Source of Revenues
In 1999, consolidated operating revenues totaled $67,456,117. The
percentages of revenues derived from customer classes are as follows:
%
Residential 32.2
Small Commercial and Industrial 28.9
Large Commercial and Industrial 15.7
Sales to Wholesale Customers for Resale 2.3
Secondary Sales 16.3
Other Sales and Other Revenues 4.6
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). In accordance with the deregulation of Maine's electric utility industry,
beginning on March 1, 2000, Van Buren and EMEC will be purchasing electricity from
other suppliers for their standard offer service. Van Buren and EMEC represented 3.0%
of consolidated MWH sales and 1.8% of consolidated operating revenues for the year
ended December 31, 1999. 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's
energy marketing subsidiary, Energy Atlantic, LLC (EA). This contract was effective
through December 31, 2000, but could be terminated on or after March 1, 2000. Like Van
Buren and EMEC, effective March 1, 2000, Houlton will be purchasing electricity from
other suppliers for their standard offer service. Including the sales to Houlton, EA's
power marketing activities accounted for 30.2% of the consolidated MWH sales in 1999.
During 1996 and 1997, the Company entered into long-term power contracts with
five of its largest customers. In exchange for discounts from the Company's standard
rates, these customers agreed to purchase all of their electrical requirements from the
Company through the year 2000. All five of these customers produced evidence of
hardship to continue operations in the area or were investigating self generation, criteria
that the Maine Public Utilities Commission (MPUC) reviewed before approving these
load-retention contracts.
On November 13, 1995, the Maine Public Utilities Commission approved a
Stipulation signed by Maine Public Service Company, the 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 until March 1, 2000 and shares operating risks and
benefits between the Company's shareholders and customers. The multi-year rate plan
was subsequently amended in January, 1998. On April 6, 1999, the MPUC approved a
March 25, 1999 Stipulation under which customer rates would not increase on April 1,
1999 as scheduled. For more information on the rate plan, see Item 3(f) of the "Legal
Proceedings" section of this Form 10-K.
For additional discussion on revenues, see the 1999 Annual Report to Stockholders,
pages 6 and 7, "Analysis of Financial Condition and Review of Operations-Operating
Revenues and Energy Sales" and pages 11 to 15, "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.
As discussed in Items 3(a) and (b) of the "Legal Proceedings" section of this Form
10-K, on June 8, 1999, the Company sold its generating assets in accordance with Maine's
new electric deregulation law.
See the 1999 Annual Report to Stockholders, pages 11 to 15, "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 and the generating asset sale, see Items 3(a) and (b)
of the "Legal Proceedings" section of this Form 10-K.
Employees
The information with respect to employees is presented in the 1999 Annual Report
to Stockholders, page 11, "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 Canadian Subsidiary). The Canadian Subsidiary
owned and operated the Tinker Station located in the Province of New Brunswick, Canada
prior to its sale on June 8, 1999.
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 wholesale marketing of
electric power and the sales of energy-related products and services. EA will begin retail
sales activity on March 1, 2000, the start of retail competition in Maine. As a start-up
unregulated subsidiary, the Board of Directors and the MPUC limited the capital
contributions to a maximum of $2 million.
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).
During 1998 and early 1999 the active interveners, 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 which resulted in the filing of a settlement agreement with the FERC on
January 19, 1999. A separate negotiated settlement filed with the FERC on February 5,
1999 resolved 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. Both settlements were found to be in the public interest
and approved by the FERC on June 1, 1999. The settlements constitute a full settlement
of all issues raised in the FERC proceeding including decommissioning-cost issues and
issues pertaining to the prudence of management, operation and decision to permanently
cease operation of the Plant.
The primary settlement provided for Maine Yankee to collect $33.1 million in the
aggregate annually, effective August 1, 1999, including both decommissioning costs and
costs related to Maine Yankee's planned independent spent fuel storage installation
(ISFSI). The 1997 FERC filing had called for an aggregate annual collection rate of $36.4
million for decommissioning and the ISFSI, based on a 1997 estimate. Pursuant to the
approved settlement the amount collected annually has been reduced to approximately
$25.6 million, effective October 1, 1999, as a result of 1999 Maine legislation allowing
Maine Yankee to (1) use for decommissioning the ISFSI funds held in trust under Maine
law for spent-fuel disposal, and (2) access approximately $6.8 million 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.
The 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 maximum allowed equity amounts, which resulted in a pro-rata refund of $9.3 million (including tax impacts) to the sponsors on July 15, 1999. The
Settling Parties also agreed 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.
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 settlement, no refunds would be
required, but such excess amounts would be credited to the customers to the extent
required by the RSP.
Finally, 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 the maximum amount would be $4.1 million for the
period.
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. Beginning in May, 1998, Maine Yankee replacement power costs have been
offset by net savings from the restructured Purchase Power Agreement with Wheelabrator-Sherman, in accordance with the rate plan stipulation. Beginning in April, 1999 the
Company began amortizing an additional $150,000 per month as part of a stipulation
described in Item 3(f) of the "Legal Proceedings" section of this Form 10-K. As of
December 31, 1999, the Company has a deferred Maine Yankee replacement power cost
balance of approximately $3.0 million, subject to recovery in accordance with the rate
plan.
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 and again in June, 1999, 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 regulation 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, 1999, is carrying on its consolidated balance
sheet a regulatory asset and a corresponding liability in the amount of $32.2 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. As discussed in Item 3(d), the
MPUC on January 27, 2000, approved a Stipulation providing for the recovery of stranded
investment, which includes the Company's share of Maine Yankee decommissioning
expenses, Maine Yankee replacement costs, and the remaining Maine Yankee investment.
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.
Year 2000 Issues
The Company encountered no computer system or operational difficulties related
to Year 2000 computer issues. The Company incurred approximately $33,000 of internal
labor for review and testing prior to December 31, 1999, which did not identify material
modifications.
Executive Officers
The executive officers of the registrant are as follows:
Office
Continuously
Name Age Held Since
Paul R. Cariani President and Chief 59 6/1/94
Executive Officer
Frederick C. Bustard Vice President, 62 6/1/99
Power Delivery
Larry E. LaPlante Vice President, 48 6/1/99
Treasurer and Chief
Financial Officer
Stephen A. Johnson Vice President, 52 6/1/99
Energy Atlantic
and General Counsel
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 Delivery
effective June 1, 1999. 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. Effective
June 1, 1996, he was elected to Vice President, Power Supply and Environment.
Larry E. LaPlante was elected to the position of Vice President, Treasurer and Chief
Financial Officer on June 1, 1999. 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. Effective June 1, 1996, he was elected to Vice President,
Finance, Administration and Treasurer.
Stephen A. Johnson was elected to the position of Vice President, Energy Atlantic
and General Counsel, effective June 1, 1999. 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. Effective June 1, 1990, he was elected to 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 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 9, 2000.
There are no family relationships among the executive officers.
Item 2. Properties
The Company owned and operated 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 Canadian
Subsidiary owned and operated 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 sold its generating assets on June
8, 1999 in accordance with the State's electric deregulation law.
Form 10-K
PART I
Item I. Business - Continued
As of December 31, 1999, the Company and Subsidiary had approximately 392 pole
miles of transmission lines and the Company owned approximately 1,728 miles of
distribution lines.
The Company was 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 was 3.3455%, or approximately 20,000 kilowatts, and was
included in the generating asset sale on June 8, 1999, as more fully described in Item 3(a)
and (b) of the "Legal Proceedings" section of this Form 10-K.
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.
Form 10-K
PART I
Item 3. Legal Proceedings
(a) Restructuring of Maine's Electric Utility Industry.
In the Company's Form 10-K's for December 31, 1996, 1997 and 1998, 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
Form 10-K
PART I
Item 3. Legal Proceedings - Continued
assets. See Item 3(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.
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.
Item 3. Legal Proceedings - Continued
In a December 15, 1999 MPUC filing, as detailed further in Item 3(d)
below, the Company updated its estimate of stranded costs to be
approximately $95.7 million, net of available value from the sale of
generating assets when deregulation occurs on March 1, 2000.
The MPUC shall include in the rates to be charged by the transmission and
distribution utility decommissioning expenses for Maine Yankee. By
2003 and no later than 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;
Item 3. Legal Proceedings - Continued
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.
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 10-K for 1998, in which the
Company reported an agreement to sell all of its generating assets to WPS
Power Development, Inc. (WPS-PDI) for $37.4 million. Further reference
is made to the Company's Form 10-Q for the quarter ended March 31,
Item 3. Legal Proceedings - Continued
1999 in which the Company described the process through which it
obtained all necessary State and Federal approvals.
The Company consummated the sale to WPS-PDI on June 8, 1999, as
reported in its Form 8-K dated June 9, 1999, after receiving all of the
major regulatory approvals. The Company's 5% ownership in Maine
Yankee was not part of the sale, since the plant is being decommissioned.
After paying Canadian, Federal and State income taxes, the remaining
proceeds, along with interest in the trust account, will be used to reduce
the Company's debt by $22.4 million. The gain from the sale has been
deferred, as required by the MPUC. The components of the deferred gain
are as follows:
(Dollars in Millions)
Gross proceeds $ 37.5
Settlement adjustments (.1)
Net proceeds 37.4
Net book value (11.5)
Excess taxes on sale of
Canadian assets (3.4)
Transition costs, net (1.8)
Deferred RSP rate increase (1.3)
Other .5
Deferred gain* $ 19.9
___________________
* The $19.9 million deferred gain above is the $20.2 million "Deferred Gain and Related Accounts" as of December 31, 1999, as
presented on page 21, "Statement of Consolidated Balance Sheets"
of the 1999 Annual Report, which information is incorporated by
reference, reduced by the remaining deferral of transition costs
allowed by the MPUC.
Upon liquidation of the subsidiary in December, 1999, $14.1 million of
the proceeds was transferred to the first mortgage trustee for eventual
paydown of long-term debt.
Item 3. Legal Proceedings - Continued
As part of the generating asset sale on June 8, 1999, the Company has
entered into two indemnity obligations with the purchaser, WPS-PDI.
First, the Company will be liable, with certain limitations, for certain
Aroostook River flowage damage. This liability will continue for ten
years after the sale and shall not exceed $2,000,000 in the aggregate.
Second, the Company has warranteed the condition of the sites sold to
WPS-PDI, with an aggregate limit of $3,000,000 for two years after the
date of sale, and five years after the sale for environmental claims. The
Company is unaware of any pending claims under either of these
indemnity obligations.
(c) 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.
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 developed and filed a proposal for
these systems on April 30, 1999. The proposal consisted of a Northern
Maine Independent System Administrator (NMISA) for northern Maine,
which must be approved by the FERC. The NMISA has been organized
as a non-profit corporation under Maine law. On August 25, 1999, the
NMISA filed its tariff with the FERC (Docket No. ER99-4225-000). The
FERC approved this tariff on November 15, 1999.
Item 3. Legal Proceedings - Continued
(d) 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,
August 11, 1999 and December 15, 1999, the Company filed its
determination of stranded costs, transmission and distribution costs and
rate design with the MPUC. The Company's amended testimony supports
its $95.7 million estimate of stranded costs, net of available value from the
sale of the generating assets, 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.
On October 15, 1999, the Company filed with the MPUC a Stipulation
resolving the revenue requirement and rate design issues for the
Company's Transmission and Distribution (T&D) utility. This Stipulation
has been signed by the Public Advocate and approval will be
recommended by the MPUC staff. Under the Stipulation, the Company's
total annual T&D revenue requirement will be $16,640,000, effective
March 1, 2000. This revenue requirement includes a 10.7% return on
equity with a capital structure based on 51% common equity. The
Stipulation further provides that the precise level of stranded cost recovery
cannot be determined until final determination of all costs associated with
the sale of the Company's generating assets (see Item 3(b) above), but
does set forth some general principles concerning the Company's ultimate
stranded costs recovery, including agreement that the major components of
the Company's stranded costs are legitimate, verifiable and unmitigable,
and therefore subject to recovery in rates, and that the 3.66% recovery
foregone in Docket 98-865 shall be added to stranded cost recovery in the
manner specified in the stipulation in that Docket (see Item 3(e) below).
The stipulation also provides that the Company's recovery of unamortized
investment tax credits and excess deferred income taxes associated with
the Company's generating assets must await a final determination ruling
Item 3. Legal Proceedings - Continued
from the IRS, which ruling has been sought by Central Maine Power
Company (CMP). On December 1, 1999, the MPUC approved this
Stipulation. In early January, 2000, CMP received its ruling from the IRS
which concluded that the unamortized investment tax credits and excess
deferred income taxes associated with the sale of the generating assets
could not be used to reduce customer rates without violating the tax
normalization rules for public utilities. Therefore, the Company has
recognized these excess deferred taxes in income, which amounted to an
increase in net income of approximately $389,000, $.24 per share.
On January 27, 2000, the MPUC approved a Stipulation in Phase II of
Docket No. 98-577 that provided for the recovery in rates of the
Company's stranded investment. The major element of the Phase II
Stipulation was the $12.5 million of stranded investment recoverable
annually beginning March 1, 2000. This revenue requirement includes a
return on unrecovered stranded investment based on the capital structure
approved by the MPUC in its December 1, 1999 Order. The approved
capital structure will consist of 51% common equity with an authorized
return on equity of 10.7%. The Phase II Stipulation also allowed the
Company to offset its unrecovered stranded investment in Seabrook by
approximately $7 million, representing an amount equal to 35% of the
available value from the sale of the generation assets. The parties to the
Phase II Stipulation also resolved several rate design issues, principally the
elimination of the inclining block rate for residential customers. In
addition, the Company was granted several accounting orders
incorporating certain accounting methodologies used in determining the
elements of stranded costs. The annual revenue requirement associated
with the recovery of stranded costs will be reviewed every two years.
With the award of the standard offer rate on November 18, 1999, and
orders approving the Company's T&D rates and stranded investment
recovery rates described above, the MPUC has established all elements of
customer rates effective March 1, 2000, the beginning of deregulation in
Maine. On average, our customers' rates will be reduced by
approximately 6%.
Item 3. Legal Proceedings - Continued
(e) Maine Public Utilities Commission Approves Common Stock Repurchase
Program, Docket No. 99-610
Reference is made to the Company's Form 10-Q, Part II, Legal
Proceedings, Item 1(d) for the quarter ended September 30, 1999, Form 8-K, Item 5(b) filed on December 1, 1999 and Item 3(d) of this Form 10-K,
in which the Company reported that stipulations resolving revenue
requirements and rate design issues for transmission and distribution rates,
as well as stranded investment, have been approved by the Maine Public
Utilities Commission (MPUC). In the Stipulations, approved by the
MPUC, the parties also agreed to a capital structure consisting of 51%
common equity and 49% of debt. After paying off debt with proceeds
from the sale of the Company's generating assets, as required under the
Company's mortgage indentures, the Company projects that the
percentage of common equity as a component in its capital structure would
exceed 51%.
In order to manage its capital structure to limit common equity to 51%, the
MPUC on November 17, 1999, approved the Company's request to
repurchase up to 500,000 shares of its common stock over a period of five
years. The shares will be repurchased through an open-market program.
Previously over a five-year period from September, 1989 to September,
1994, the Company purchased 250,000 shares at a cost of $5.7 million, all
of which are held in treasury shares, in order to maintain the Company's
capital structure at levels appropriate for an investor-owned electric utility.
(f) Maine Public Utilities Commission Approves Rate Plan Stipulation,
Docket No. 98-685
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, the Company's Form 10-K for December 31, 1998
describes a January, 1998 Stipulation approved by the MPUC in Docket
No. 97-830, which established the rate increase beginning February 1,
1998 and the minimum rate increase effective February 1, 1999. The
Stipulation also prescribes that the savings from the restructured
Wheelabrator-Sherman (W-S) Power Contract would offset Maine Yankee
Item 3. Legal Proceedings - Continued
replacement power costs. For the final year of the rate plan beginning
February 1, 1999, the Company filed, on November 13, 1998, 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. On December 15, 1998, the MPUC granted the
Company's request to defer the increase to April 1, 1999, as well as extend
the rate plan by one month to February 29, 2000, to coincide with the start
of retail competition in Maine.
In its April 6, 1999 Order, the MPUC approved a March 25, 1999
Stipulation between the Office of the Public Advocate (OPA) and the
Company. Under this Stipulation, customer rates would not increase on
April 1, 1999, if the MPUC approved the sale of the Company's
generation assets as described in Item (b) above. The approval of the
Stipulation also resolved certain issues associated with the treatment of
capacity cost savings from the closure of Maine Yankee under the
Company's rate stabilization plan.
The principal provisions are as follows:
1) The Company is entitled to a 3.66% specified rate increase as of
April 1, 1999. Rather than increase customer rates, the Company
will recognize the revenues that this increase would have generated
and, correspondingly, record a deferred asset on the Company's
books of account. The parties to the Stipulation also agreed to
recommend the use in rates of available value from the asset sale
corresponding with the specified rate increase once the MPUC
determines the Company's allowed stranded cost recovery in Docket
No. 98-577, Public Utilities Commission, Investigation of Stranded
Costs, Transmission and Distribution Utility, Revenue
Requirements and Rate Design of Maine Public Service Company.
As described in Item 3(d) above, the MPUC approved the use of
available value in its December 1, 1999 order.
2) The Stipulation also resolves a dispute over the determination of
Maine Yankee replacement power costs. The Stipulation allows the
Company to continue to recognize and defer Maine Yankee
replacement power costs on an energy-only basis, offset by
Item 3. Legal Proceedings - Continued
Wheelabrator-Sherman contract restructuring savings, through the
end of the rate plan. The Company agreed to begin amortizing on
April 1, 1999, Maine Yankee replacement power costs in the
amount of $150,000 per month or a total of $1,650,000 for the
remaining eleven months of the rate plan.
3) With the Commission's approval of the generation asset sale, the
parties agreed that the Company would not increase retail rates on
April 1, 1999, to reflect any increase under the Maine Yankee
replacement power provision of the rate plan. Any Maine Yankee
deferred replacement costs will be deferred, and, beginning on
March 1, 2000, will be offset by a corresponding amount of
available value as allowed in Docket No. 98-577.
Item 4. Submission of Matters To a Vote of Security Holders
At the Company's Annual Meeting of Stockholders, held on May 11, 1999
the only matter voted upon was the uncontested election of the following
directors to serve until the 2002 Annual Meeting of Stockholders, each of
whom received the votes shown:
Non-votes and
Nominee For Against Abstentions
D. James Daigle 1,322,208 18,886 276,156
Deborah L. Gallant 1,322,741 18,353 276,156
G. Melvin Hovey 1,320,288 20,806 276,156
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, 1999, there were 1,175 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
1999
First Quarter $16-1/8 $13-1/8 $ .25 $ .25
Second Quarter $17-7/8 $12-7/8 .25 .25
Third Quarter $19-1/8 $17-7/16 .25 .30
Fourth Quarter $19 $16-1/2 .30 .30
Total Dividends $ 1.05 $1.10
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
Dividends declared within the quarter are paid on the first day of the succeeding
quarter.
See Note 7 to the financial statements incorporated herein by reference
concerning restrictions on payment of dividends on Common Stock.
Item 6. Selected Financial Data
A five-year summary of selected financial data (1995-1999) is included on
page 16 of the Company's 1999 Annual Report to Stockholders, which
summary is incorporated herein by reference.
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 6 to 15, Exhibit 13, 1999 Annual Report to
Shareholders, which pages are hereby incorporated herein by reference.
Information regarding "Construction" is also furnished in Note 11,
"Commitments, Contingencies, and Regulatory Matters", of the Notes to
the Consolidated Financial Statements, pages 30 to 35 of the 1999 Annual
Report to Shareholders, which pages are hereby incorporated herein by
reference.
Item 8. Financial Statements and Supplementary Data
(a) The following financial statements and supplementary data are
included in the Company's 1999 Annual Report to Stockholders on pages
17 through 35, and are incorporated herein by reference:
Report of Independent Accountants.
Statements of Consolidated Operations for the years ended
December 31, 1999, 1998 and 1997.
Statements of Consolidated Cash Flows for the years ended
December 31, 1999, 1998 and 1997.
Consolidated Balance Sheets as of December 31, 1999 and
1998.
Statements of Consolidated Common Shareholders' Equity for
the years ended December 31, 1999, 1998 and 1997.
Consolidated Statements of Capitalization as of December 31,
1999 and 1998.
Notes to Consolidated Financial Statements.
Item 9. Changes In And Disagreements With Accountants On Accounting and Financial Disclosure
None.
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 2000 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 2000 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 2000 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 2000 Annual Meeting of Stockholders, which
information is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
Not applicable.
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
18 through 35 of the 1999 Annual Report to Stockholders:
Statements of Consolidated Operations for years ended
December 31, 1999, 1998 and 1997.
Statements of Consolidated Cash Flows for the years ended
December 31, 1999, 1998 and 1997.
Consolidated Balance Sheets as of December 31, 1999 and
1998.
Statements of Consolidated Common Shareholders' Equity for
the years ended December 31, 1999, 1998 and 1997.
Consolidated Statements of Capitalization as of December 31,
1999 and 1998.
Notes to Consolidated Financial Statements.
(2) Financial Statement Schedules
Included in Part IV of this report:
Form 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K -
Continued
Page
Report of Independent Accountants 45
Schedule II - Valuation of Qualifying Accounts 46
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)
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. (Exhibit 4(t) to the Company's 1998 Form 10-K)
4(u) Eighteenth Supplemental Indenture, Dated April 1,
1998.
(Exhibit 4(u) to the Company's 1998 Form 10-K)
4(v) Nineteenth Supplemental Indenture, Dated May 1,
1998.
(Exhibit 4(v) to the Company's 1998 Form 10-K)
9 Not applicable.
10(a)(1) Joint Ownership Agreement with Public Service of
New Hampshire in respect to construction of two
nuclear generating units designated as Seabrook Units 1
and 2, together with related amendments to date.
(Exhibit 10 to the Company's 1980 Form 10-K)
10(a)(2) Twentieth Amendment to Joint Ownership Agreement.
(Exhibit 10(a)(6) to the Company's 1986 Form 10-K)
10(a)(3) Twenty-Second Amendment to Joint Ownership
Agreement. (Exhibit 10(a)(3) to the 1988 Form 10-K)
10(b)(1) Capital Funds Agreement, dated as of May 20, 1968
between Maine Yankee Atomic Power Company and
the Company. (Exhibit 10(b)(1) to Form 10-Q for the
quarter ended March 31, 1983)
10(b)(2) Power Contract, dated as of May 20, 1968 between
Maine Yankee Atomic Power Company and the
Company. (Exhibit 10(b)(2) to Form 10-Q for the
quarter ended March 31, 1983)
10(c)(1) Participation Agreement, as of June 20, 1969, with
Maine Electric Power Company, Inc. (Exhibit 10(c)(1)
to Form 10-Q for the quarter ended March 31, 1983)
10(c)(2) Agreement, as of June 20, 1969, among the Company
and the other Maine Participants. (Exhibit 10(c)(2) to
Form 10-Q for quarter ended March 31, 1983)
10(c)(3) Power Purchase and Transmission Agreement
Supplement to Participation Agreement, dated as of
August 1, 1969, with Maine Electric Power Company,
Inc. (Exhibit 10(c)(3) to Form 10-Q for quarter ended
March 31, 1983)
10(c)(4) Supplement Amending Participation Agreement, as of
June 24, 1970, with Maine Electric Power Company,
Inc. (Exhibit 10(c)(4) to Form 10-Q for quarter ended
March 31, 1983)
10(c)(5) Second Supplement to Participation Agreement, dated
as of December 1, 1971, including as Exhibit A the
Unit Participation Agreement dated November 15,
1971, as amended, between Maine Electric Power
Company, Inc. and the New Brunswick Electric Power
Commission. (Exhibit 10(c)(5) to Form 10-Q for
quarter ended March 31, 1983)
10(c)(6) Agreement and Assignment, as of August 1, 1977, by
Connecticut Light & Power Company, Hartford Electric
Company, Holyoke Water Power Company, Holyoke
Power Company, Western Massachusetts Electric
Company and the Company. (Exhibit 10(c)(6) to Form
10-Q for the quarter ended March 31, 1983)
10(c)(7) Amendment dated November 30, 1980 to Agreement
and Assignment as of August 1, 1977, between
Connecticut Light & Power Company, Hartford Electric
Company, Holyoke Water Power Company, Holyoke
Power Company, Western Massachusetts Electric
Company and the Company. (Exhibit 10(c)(7) to Form
10-Q for the quarter ended March 31, 1983)
10(c)(8) Assignment Agreement as of January 1, 1981, between
Central Maine Power Company and the Company.
(Exhibit 10(c)(8) to Form 10-Q for the quarter ended
March 31, 1983)
10(d) Wyman Unit #4 Agreement for Joint Ownership as of
November 1, 1974, with Amendments 1, 2, and 3, dated
as of June 30, 1975, August 16, 1976, December 31,
1978, respectively. (Exhibit 10(d) to Form 10-Q for the
quarter ended March 31, 1983)
10(e) Agreement between Sherman Power Company and
Maine Public Service Company, dated June 4, 1984,
with amendments dated July 12, 1984 and February 14,
1985. (Exhibit 10(f) to 1984 Form 10-K)
10(f) Credit Agreement, dated as of October 8, 1987 among
the Registrant and The Bank of New York, Bank of
New England, N.A., The Merrill Trust Company and
The Bank of New York, as agent for the Participating
Banks. (Exhibit 10(g) to Form 8-K dated October 13,
1987)
10(g) Amendment No. 1, dated as of October 8, 1989, to the
Revolving Credit Agreement, dated as of October 8,
1987, among the Registrant and The Bank of New
York, Bank of New England, N.A., Fleet Bank
(formerly the Merrill Trust Company) and The Bank of
New York as agent for the participating banks. (Exhibit
10(l) to Form 8-K dated September 22, 1989)
10(h) Amendment No. 2, dated as of June 5, 1992, to the
Revolving Credit Agreement, among the Registrant and
The Bank of New York, Bank of New England, N.A.,
Shawmut Bank and the Bank of New York, as agent for
the participating banks. (Exhibit 10(h) to the
Company's 1992 Form 10-K)
10(i) Indenture of Second Mortgage and Deed of Trust, dated
as of October 1, 1985, made by the Registrant to J.
Henry Schroder Bank and Trust Company, as Trustee.
(Exhibit 10(i) to Form 8-K dated November 1, 1985)
10(j) First Supplemental Indenture Dated March 1, 1991.
(Exhibit 10(i) to the Company's 1991 Form 10-K)
10(k) Second Supplemental Indenture Dated September 1,
1991. Exhibit 10(j) to the Company's 1991 Form 10-K)
10(l) Agency Agreement dated as of October 1, 1985,
between J. Henry Schroder Bank and Trust Company,
as Trustee under the Indenture of Second Mortgage and
Deed of Trust dated as of October 1, 1985, made by the
Registrant to J. Henry Schroder Bank and Trust
Company, as Trustee, and Continental Illinois National
Bank and Trust Company, as Trustee, under an
Indenture of Mortgage and Deed of Trust, dated as of
October 1, 1945, as amended and supplemented, made
by the Registrant to Continental Illinois National Bank
and Trust Company, as Trustee. (Exhibit 10(j) to Form
8-K dated November 1, 1985)
Executive Compensation Plans and Arrangements
10(m) Employment Contract between Frederick C. Bustard
and Maine Public Service Company dated 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 November 5,
1999.
*10(o) Employment Contract between Stephen A. Johnson and
Maine Public Service Company dated November 5,
1999.
*10(p) Employment Contract between Larry E. LaPlante and
Maine Public Service Company, dated November 5,
1999.
*10(q) Employment Contract between William L. Cyr and
Maine Public Service Company, dated November 5,
1999.
10(r) Maine Public Service Company, Prior Service
Executive Retirement Plan, dated May 12, 1992.
(Exhibit 10(s) to 1992 Form 10-K)
10(s) Maine Public Service Company Pension Plan. (Exhibit
10(t) to 1992 Form 10-K)
10(t) Maine Public Service Company Retirement Savings
Plan. (Exhibit 10(u) to 1992 Form 10-K)
10(u) Third Supplemental Indenture Dated as of June 1, 1996.
(Exhibit 10(t) to 1996 Form 10-K)
10(v) 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(w) Fourth Supplemental Indenture dated May 1, 1998.
(Exhibit 10(v) to the Company's 1998 Form 10-K)
10(x) Agreement between WPS Power Development, Inc. and
Maine Public Service Company, dated July 7, 1998.
(Exhibit 10(w) to the Company's 1998 Form 10-K)
10(y) 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. (Exhibit 10(x) to the
Company's 1998 Form 10-K)
10(z) Agreement between Loring Development Authority of
Maine and Maine Public Service Company, dated July
9, 1998. (Exhibit 10(y) to the Company's 1998 Form
10-K)
11 Not applicable.
12 Not applicable.
*13 1999 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)
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)
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). (Exhibit 99(q) to the Company's
1998 Form 10-K)
99(r) Order of Maine Public Utilities Commission dated
September 21, 1998 in Docket 98-138 (Formation of
marketing affiliate). (Exhibit 99(r) to the Company's
1998 Form 10-K)
99(s) Order of Maine Public Utilities Commission dated
December 15, 1998 in Docket 98-865 (Annual Increase
Under Rate Stabilization Plan). (Exhibit 99(s) to the
Company's 1998 Form 10-K)
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. (Exhibit 99(t) to the Company's 1998
Form 10-K)
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. (Exhibit 99(u) to the Company's 1998
Form 10-K)
99(v) Order of the Federal Energy Regulatory Commission
dated December 22, 1998 in Docket No. ER95-836-000. (Exhibit 99(v) to the Company's 1998 Form 10-K)
*99(w) Order of Maine Public Utilities Commission dated
April 5, 1999 in Docket 98-584 (Generating Asset Sale
Approval).
*99(x) Order of the Federal Energy Regulatory Commission
dated April 14, 1999 in Docket EC 99-29-000
(Generating Asset Sale Approval).
*99(y) Order of the Federal Energy Regulatory Commission
dated November 15, 1999 in Docket ER 99-4225-000
(Independent System Administrator).
*99(z) Order of Maine Public Utilities Commission dated
December 1, 1999 in Docket 98-577 (Stipulation
Approval).
*99(aa) Order of Maine Public Utilities Commission dated
December 3, 1999 in Docket 99-111 (Energy Atlantic
as Central Maine Power Standard Offer Provider).
*99(ab) Order of Maine Public Utilities Commission dated
February 17, 2000 in Docket 98-577 (Order Approving
Phase II Stipulation).
(b) A Form 8-K was filed on: January 27, 1999, under item 5, Other
Events; April 28, 1999, under item 5, Other Events; June 9, 1999,
under item 5, Other Events; December 1, 1999, under item 5, Other
Events and February 8, 2000, 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 21st of March, 2000.
MAINE PUBLIC SERVICE COMPANY
By: /s/ Larry E. LaPlante
Larry E. LaPlante
Vice President, Treasurer and CFO
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 3/3/00
(G. Melvin Hovey)
/s/ Paul R. Cariani President and Director 3/3/00
(Paul R. Cariani)
/s/ Robert E. Anderson Director 3/3/00
(Robert E. Anderson)
/s/ Donald F. Collins Director 3/3/00
(Donald F. Collins)
/s/ D. James Daigle Director 3/3/00
(D. James Daigle)
/s/ Richard G. Daigle Director 3/3/00
(Richard G. Daigle)
/s/ J. Gregory Freeman Director 3/7/00
(J. Gregory Freeman)
/s/ Deborah L. Gallant Director 3/3/00
(Deborah L. Gallant)
/s/ Nathan L. Grass Director 3/3/00
(Nathan L. Grass)
/s/ J. Paul Levesque Director 3/7/00
(J. Paul Levesque)
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 10, 2000 appearing on page 17 of the 1999 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.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Portland, Maine
February 10, 2000
Maine Public Service Company & Subsidiary
Valuation of Qualifying Accounts & Reserves
For the Years Ended December 31, 1999, 1998, & 1997
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:
1999 215,000 171,323 119,690 291,013 215,000
1998 215,000 181,360 129,022 310,382 215,000
1997 207,029 182,706 124,397 299,132 215,000
Exhibit 10(n)
EMPLOYMENT CONTINUITY AGREEMENT
This Agreement made as of this 5th day of November, 1999, but effective
September 13, 1999, by and between MAINE PUBLIC SERVICE COMPANY, a
Maine corporation with its principal place of business in Presque Isle, Maine (the
"Company") and Paul R. Cariani of Presque Isle, Maine, ("Officer").
WHEREAS, the Officer has been employed by the Company in a senior
management capacity for over16 years, and is now its President and CEO ; and
WHEREAS, the Officer's knowledge of the Company's affairs and his
experience are critical to the protection and enhancement of the best interests of the
Company, its employees, ratepayers and stockholders; and
WHEREAS, in the current business climate acquisitions of smaller,
independently-operated utility companies is common; and
WHEREAS, the Company desires to assure itself of the continued employment
of the Officer and the benefit of his independent judgment in the operation of the
Company, particularly in the event that any such acquisition was being considered, in
light of the disruption resulting from such event;
WHEREAS, the Company and the Officer entered into an Employment
Continuity Agreement, dated August 22, 1989; and
WHEREAS, Section 14 of the Agreement provides that the Agreement may be
amended in writing by the parties; and
WHEREAS, the parties desire to amend and restate the Agreement as set forth
herein;
NOW, THEREFORE, in consideration of the mutual promises and undertakings
herein contained and for other good and valuable consideration, the receipt and
adequacy of which is acknowledged by each of the parties, the Officer and the
Company agree as follows:
1. Term of the Agreement and Renewal. The term of this Agreement shall be
for a period beginning September 13, 1999, and ending December 31, 2001. On
January 1, 2002, and on January 1 of each period of three (3) years thereafter (in each
case such date to be a "Renewal Date") this Agreement automatically shall be renewed
for an additional three (3) year term, unless at least one (1) year prior to any such
Renewal Date, either party shall have given written notice to the other that such
renewal shall not take place. Such notice may be given by the Company only upon the
affirmative vote of the Compensation Committee of the Board of Directors.
2. Rights Upon Involuntary Termination of Employment. If, within twenty-four (24) months after the occurrence of a Change in Control Event, the Company
terminates the Officer's employment for any reason other than Good Cause as defined
in Paragraph 4, or if the Officer voluntarily terminates employment for Good Reason
as defined in Paragraph 3, the Company shall provide the Officer with the following:
(a) Within thirty (30) days of such termination, a lump sum cash
payment in an amount equal to the sum of:
(i) two hundred percent (200%) of the Officer's annual base
salary in effect upon the date of the Change in Control Event, and
(ii) two hundred percent (200%) of the award the Officer would
have received for the year in which such termination occurs, pursuant to
the Maine Public Service Company Incentive Compensation Plan,
assuming that his employment had not terminated and that for such year
all applicable performance goals will be met.
(b) The continuation of the Officer's participation and the participation
of his dependents (to the extent they were participating prior to his termination
of employment) in the Company's health, life, disability and other employee
benefit plans, programs and arrangements (excluding the Maine Public Service
Company Pension Plan and the Maine Public Service Company Non-Union
Retirement Savings Plan) for a period of twenty-four (24) months after such
termination as if he were still employed during such period; provided, however,
if such participation in any such plan, program or arrangement is specifically
prohibited by the terms thereof, the Company shall provide the Officer (and his
dependents) with benefits substantially similar to those which he was entitled to
receive under such plan, program or arrangement immediately prior to his
termination of employment. Additionally, at the end of any period of such
coverage, the Officer shall have the right to have assigned to him, for the cash
surrender value thereof, any assignable insurance owned by the Company on the
life of the Officer. For purposes of this Paragraph 2(b), any employee benefit
determined with reference to the Officer's compensation or earnings shall be
based on his annual base salary unless otherwise provided under the terms of the
applicable employee benefit plan, program or arrangement.
(c) The Company shall pay the Officer an amount equal to the award he
would have been entitled to receive under the Company's Incentive
Compensation Plan, if his employment had not terminated, based on the base
salary he had earned as of his termination date, and assuming that for such year
all applicable performance goals will be met. Such payment shall be made
within ninety (90) days after his employment terminates.
3. Termination for Good Reason. For purposes of this Agreement,
termination by the Officer of his employment for "Good Reason," except upon the
Officer's express written consent otherwise, shall mean:
(a) the assignment of duties to the Officer which:
(i) are materially different from his duties immediately prior to the
Change in Control Event, or
(ii) result in his having significantly less authority or responsibility
than he had prior to the Change in Control Event; or
(b) the Officer's removal from, or any failure to re-elect him to, any
position he held immediately prior to the Change in Control Event with either the
Company or any majority-owned subsidiary; or
(c) a reduction of the Officer's annual base salary in effect on the date of
the Change in Control Event or as the same may be increased from time to time
thereafter; or
(d) the Company's transferring or assigning the Officer to a place of
employment more than twenty-five (25) miles from Presque Isle, Maine, except for
required business travel to an extent substantially consistent with his business travel
obligations immediately prior to the Change in Control Event; or
(e) the Company's failure to provide the Officer with substantially the same
health, life and other employee benefit plans, programs and arrangements
(specifically including the Company's compensation and incentive plans, as the
same may be amended in the future), and substantially the same perquisites of
employment, as provided to him immediately prior to the Change in Control Event
or as the same may be increased thereafter; or
- the Company's failure to provide the Officer with substantially the same
support staff as provided to him immediately prior to the Change in
Control Event; or
- the Company's failure to increase the Officer's salary, employee
benefits or perquisites of employment in a manner or amount
commensurate with increases provided to the Company's other
executive officers; or
- the Company's failure to obtain from any successor a satisfactory
agreement to assume and perform the terms of this Agreement.
4. Termination by Reason of Death or for Good Cause. Notwithstanding any
provision of this Agreement to the contrary, no benefits are payable hereunder upon the
Officer's death prior to his involuntary termination of employment pursuant to Paragraph
2 or voluntary termination of employment for Good Reason pursuant to Paragraph 3. The
Company retains the right to terminate the Officer for "Good Cause," in which event he
shall not be entitled to receive any payment or benefits pursuant to this Agreement. "Good
Cause" shall mean:
(a) the Officer's conviction, by a court of competent jurisdiction, of a crime
adversely reflecting on his honesty, trustworthiness or fitness to carry out the
responsibilities of his position with the Company in other respects; or
(b) a willful breach by him of any material duty or obligation imposed
upon him under the terms of his employment, as those terms existed immediately
prior to any Change in Control Event, and his failure to cure such breach within
thirty (30) days after receiving notice thereof from the Company.
5. "Change in Control Event." Each of the following events shall constitute a
"Change in Control Event" for purposes of this Agreement:
(a) Any person acquires beneficial ownership of Company securities and
is or thereby becomes a beneficial owner of securities entitling such person to
exercise twenty-five percent (25%) or more of the combined voting power of the
Company's then outstanding stock.
For purposes of this Agreement, "beneficial ownership" shall be determined
in accordance with Regulation 13D under the Securities Exchange Act of 1934, or
any similar successor regulation or rule; and the term "person" shall include any
natural person, corporation, partnership, trust or association, or any group or
combination thereof, whose ownership of Company securities would be required
to be reported under such Regulation 13D, or any similar successor regulation or
rule.
(b) The Company ceases to be a reporting company pursuant to Section
13(a) of the Securities Exchange Act of 1934 or any similar successor provision.
(c) The number of the Company's Outside Directors, as defined herein, is
decreased by more than fifty percent (50%) in any twenty-five (25) month period
or the number of the Company's directors is increased such that the Outside
Directors constitute less than a majority of the Board.
(d) Within any twenty-five (25) month period, individuals who were
Outside Directors at the beginning of such period, together with any other Outside
Directors first elected as directors of the Company pursuant to nominations
approved or ratified by at least two-thirds (2/3) of the Outside Directors in office
immediately prior to such respective elections, cease to constitute a majority of the
board of directors of the Company.
(e) The Company is subject to a change in control which would require
reporting in response to Item 1 of Form 8-K under Regulation 13a-11 promulgated
under the Securities Exchange Act of 1934, as amended, or any similar successor
statute or rule, whether or not the Company is a reporting company under such Act.
(f) The Company's stockholders approve:
(i) any consolidation or merger of the Company in which the
Company is not the continuing or surviving corporation or pursuant to which
shares of Company common stock would be converted into cash, securities
or other property, other than a merger or consolidation of the Company in
which the holders of the Company's common stock immediately prior to the
merger or consolidation have substantially the same proportionate ownership
and voting control of the surviving corporation immediately after the merger
or consolidation; or
(ii) any sale, lease, exchange, liquidation or other transfer (in one
transaction or a series of transactions) of all or substantially all of the
assets of the Company.
Notwithstanding subparagraphs (i) and (ii) above, the term "Change in Control
Event" shall not include a consolidation, merger, or other reorganization if upon
consummation of such transaction all of the outstanding voting stock of the
Company is owned, directly or indirectly, by a holding company, and the holders
of the Company's common stock immediately prior to the transaction have
substantially the same proportionate ownership and voting control of the holding
company.
6. Outside Directors. For purposes of this Agreement, an "Outside Director" as
of a given date shall mean a member of the Company's board of directors who has been
a director of the Company throughout the six (6) months prior to such date and who has
not been an employee of the Company at any time during such six (6) month period.
7. Notices. Any and all notices required or permitted to be given hereunder shall
be in writing and shall be deemed to have been given when deposited in the United States
mails, certified or registered mail, postage prepaid and addressed as follows:
To the Officer: Paul R. Cariani
68 Pine Street
Presque Isle, Maine 04769-2937
To the Company: Maine Public Service Company
P. 0. Box 1209
Presque Isle, Maine 04769-1209
Either party may change by notice to the other the address to which notices to it are to be
addressed.
- Applicable Law, Taxes, Binding Agreement, Severability, Construction.
- This Agreement shall be governed by and construed in accordance
with the laws of the State of Maine, except as to any matter which is
preempted by federal law.
- Notwithstanding anything to the contrary herein contained, the
Company may withhold from any amounts payable under this
Agreement all federal, state or other taxes or assessments which
may be required by applicable statute or regulation to be withheld.
- This Agreement shall be binding upon and inure to the benefit of the
Officer, his heirs, assigns, executors and legal representatives; and
the Company, its successors and assigns.
- If any provision of this Agreement shall be held invalid or
unenforceable by a court of competent jurisdiction, the remainder of
this Agreement shall not be affected thereby.
- The Outside Directors shall have the authority to construe and
interpret this Agreement on behalf of the Company, and any such
determination by the Outside Directors shall be conclusive on the
Company.
9. Limitation on Amount to be Paid. If payment of any amount under this
Agreement would cause the Officer to be subject to an excise tax pursuant to Section
4999 of the Internal Revenue Code (as amended from time to time) or the regulations
thereunder, then such amount shall not be paid to the extent necessary to avoid the
imposition of such tax. The preceding sentence shall apply only if the aggregate
amount payable to the Officer or for his benefit under the Agreement, after payment of
such excise tax, would be less than the aggregate amount payable in accordance with
the preceding sentence.
10. Funding. This Agreement shall not be construed to create or require the
Company to create a trust or to otherwise act to fund the amounts payable hereunder.
11. Assignment. Except as required by law, the right to receive payments
hereunder shall not be subject to alienation, assignment, garnishment, attachment,
execution or levy of any kind, and any attempt to cause such payments to be so subject
shall not be recognized by the Company.
12. Execution of Further Documents. In the event the Officer receives
payments or benefits pursuant to the terms hereof and the Company's independent
counsel deems it necessary for the Company to receive a release or other
acknowledgment, the Officer agrees to execute any such document, as may be
reasonably required as a condition of his receipt of such payment or benefits.
13. Amendment and Waiver. The Agreement may be amended only in
writing, by the parties hereto, and no condition or provision of the Agreement may be
waived except in writing. Waiver by either party at any time of the other party's breach
of, or failure to comply with, any condition or provision of this Agreement to be
performed by such other party shall not be deemed a waiver of any other provision or
condition at the same time or of any provision or condition at any prior or subsequent
time, unless specifically stated therein.
14. Arbitration. In recognition of the mutual benefits of arbitration, the parties
hereby agree that arbitration as provided for herein shall be the exclusive remedy for
resolving any claim or dispute arising under this Agreement, and hereby mutually
waive any and all other remedies at law or in equity for determining any such claim or
dispute.
(a) Any arbitration under this Agreement, and any related judicial
proceeding, shall be initiated and shall proceed pursuant to the provisions of the
Maine Uniform Arbitration Act (the "Act") and, to the extent consistent with the
Act, the then prevailing rules of the American Arbitration Association (the
"Association") for labor and employment contracts. To initiate arbitration
hereunder, demand shall be given in writing to the Association and the other party
no later than one year after the claim arises. Any claim for which such demand is
not made within one year after the claim arises shall be barred and discharged
absolutely.
(b) Any arbitration under this Agreement shall be before a single
arbitrator, and an award in such arbitration may include only damages which the
arbitrator determines to be due under express provisions of this Agreement. The
arbitrator shall have no authority to award any other damages, including without
limitation, consequential and exemplary damages. Any award in arbitration shall
be subject to enforcement and appeal pursuant to the Act.
(c) The parties shall share equally all costs and fees charged by the
Association or the arbitrator.
15. No Additional Effect. Except as expressly provided herein, nothing
contained herein shall be construed to provide the Officer with any specific period of
employment, right to be retained in the service of the Company or other rights, nor
shall this Agreement be construed to otherwise limit the rights of the Company to
discharge or take other action with respect to the Officer.
IN WITNESS WHEREOF, the parties have executed this Agreement as of the day
and year first above written.
Witness: MAINE PUBLIC SERVICE COMPANY
/s/ Alice E. Shepard By /s/ Nathan L. Grass
Its Chairman, Executive Compensation
Committee
/s/ Alice E. Shepard /s/ Paul R. Cariani
Officer Paul R. Cariani
Exhibit 10(o)
EMPLOYMENT CONTINUITY AGREEMENT
This Agreement made as of this 5th day of November, 1999, but effective
September 13, 1999, by and between MAINE PUBLIC SERVICE COMPANY, a
Maine corporation with its principal place of business in Presque Isle, Maine (the
"Company") and Stephen A. Johnson of Presque Isle, Maine, ("Officer").
WHEREAS, the Officer has been employed by the Company in a senior
management capacity for over 14 years, and is now its General Counsel and Vice
President, Energy Atlantic; and
WHEREAS, the Officer's knowledge of the Company's affairs and his experience
are critical to the protection and enhancement of the best interests of the Company, its
employees, ratepayers and stockholders; and
WHEREAS, in the current business climate acquisitions of smaller, independently-operated utility companies is common; and
WHEREAS, the Company desires to assure itself of the continued employment of
the Officer and the benefit of his independent judgment in the operation of the
Company, particularly in the event that any such acquisition was being considered, in
light of the disruption resulting from such event;
WHEREAS, the Company and the Officer entered into an Employment Continuity
Agreement, dated August 22, 1989; and
WHEREAS, Section 14 of the Agreement provides that the Agreement may be
amended in writing by the parties; and
WHEREAS, the parties desire to amend and restate the Agreement as set forth
herein;
NOW, THEREFORE, in consideration of the mutual promises and undertakings
herein contained and for other good and valuable consideration, the receipt and
adequacy of which is acknowledged by each of the parties, the Officer and the
Company agree as follows:
1. Term of the Agreement and Renewal. The term of this Agreement shall be
for a period beginning September 13, 1999, and ending December 31, 2001. On
January 1, 2002, and on January 1 of each period of three (3) years thereafter (in each
case such date to be a "Renewal Date") this Agreement automatically shall be renewed
for an additional three (3) year term, unless at least one (1) year prior to any such
Renewal Date, either party shall have given written notice to the other that such
renewal shall not take place. Such notice may be given by the Company only upon the
affirmative vote of the Compensation Committee of the Board of Directors.
2. Rights Upon Involuntary Termination of Employment. If, within twenty-four (24) months after the occurrence of a Change in Control Event, the Company
terminates the Officer's employment for any reason other than Good Cause as defined
in Paragraph 4, or if the Officer voluntarily terminates employment for Good Reason
as defined in Paragraph 3, the Company shall provide the Officer with the following:
(a) Within thirty (30) days of such termination, a lump sum cash payment
in an amount equal to the sum of:
(i) two hundred percent (200%) of the Officer's annual base
salary in effect upon the date of the Change in Control Event, and
(ii) two hundred percent (200%) of the award the Officer would
have received for the year in which such termination occurs, pursuant to the
Maine Public Service Company Incentive Compensation Plan, assuming
that his employment had not terminated and that for such year all applicable
performance goals will be met.
(b) The continuation of the Officer's participation and the participation of
his dependents (to the extent they were participating prior to his termination of
employment) in the Company's health, life, disability and other employee benefit
plans, programs and arrangements (excluding the Maine Public Service Company
Pension Plan and the Maine Public Service Company Non-Union Retirement Savings
Plan) for a period of twenty-four (24) months after such termination as if he were still
employed during such period; provided, however, if such participation in any such
plan, program or arrangement is specifically prohibited by the terms thereof, the
Company shall provide the Officer (and his dependents) with benefits substantially
similar to those which he was entitled to receive under such plan, program or
arrangement immediately prior to his termination of employment. Additionally, at the
end of any period of such coverage, the Officer shall have the right to have assigned to
him, for the cash surrender value thereof, any assignable insurance owned by the
Company on the life of the Officer. For purposes of this Paragraph 2(b), any employee
benefit determined with reference to the Officer's compensation or earnings shall be
based on his annual base salary unless otherwise provided under the terms of the
applicable employee benefit plan, program or arrangement.
(c) The Company shall pay the Officer an amount equal to the award he
would have been entitled to receive under the Company's Incentive Compensation
Plan, if his employment had not terminated, based on the base salary he had earned as
of his termination date, and assuming that for such year all applicable performance
goals will be met. Such payment shall be made within ninety (90) days after his
employment terminates.
3. Termination for Good Reason. For purposes of this Agreement,
termination by the Officer of his employment for "Good Reason," except upon the
Officer's express written consent otherwise, shall mean:
(a) the assignment of duties to the Officer which:
(i) are materially different from his duties immediately prior to the
Change in Control Event, or
(ii) result in his having significantly less authority or responsibility
than he had prior to the Change in Control Event; or
(b) the Officer's removal from, or any failure to re-elect him to, any position
he held immediately prior to the Change in Control Event with either the Company or any
majority-owned subsidiary; or
(c) a reduction of the Officer's annual base salary in effect on the date of the
Change in Control Event or as the same may be increased from time to time thereafter; or
(d) the Company's transferring or assigning the Officer to a place of
employment more than twenty-five (25) miles from Presque Isle, Maine, except for
required business travel to an extent substantially consistent with his business travel
obligations immediately prior to the Change in Control Event; or
(e) the Company's failure to provide the Officer with substantially the same
health, life and other employee benefit plans, programs and arrangements (specifically
including the Company's compensation and incentive plans, as the same may be amended
in the future), and substantially the same perquisites of employment, as provided to him
immediately prior to the Change in Control Event or as the same may be increased
thereafter; or
(f) the Company's failure to provide the Officer with substantially the same
support staff as provided to him immediately prior to the Change in Control Event; or
(g) the Company's failure to increase the Officer's salary, employee benefits
or perquisites of employment in a manner or amount commensurate with increases
provided to the Company's other executive officers; or
(h) the Company's failure to obtain from any successor a satisfactory
agreement to assume and perform the terms of this Agreement.
4. Termination by Reason of Death or for Good Cause. Notwithstanding any
provision of this Agreement to the contrary, no benefits are payable hereunder upon the
Officer's death prior to his involuntary termination of employment pursuant to Paragraph
2 or voluntary termination of employment for Good Reason pursuant to Paragraph 3. The
Company retains the right to terminate the Officer for "Good Cause," in which event he
shall not be entitled to receive any payment or benefits pursuant to this Agreement. "Good
Cause" shall mean:
(a) the Officer's conviction, by a court of competent jurisdiction, of a crime
adversely reflecting on his honesty, trustworthiness or fitness to carry out the
responsibilities of his position with the Company in other respects; or
(b) a willful breach by him of any material duty or obligation imposed
upon him under the terms of his employment, as those terms existed immediately prior
to any Change in Control Event, and his failure to cure such breach within thirty (30)
days after receiving notice thereof from the Company.
5. "Change in Control Event." Each of the following events shall constitute a
"Change in Control Event" for purposes of this Agreement:
(a) Any person acquires beneficial ownership of Company securities and
is or thereby becomes a beneficial owner of securities entitling such person to exercise
twenty-five percent (25%) or more of the combined voting power of the Company's
then outstanding stock.
For purposes of this Agreement, "beneficial ownership" shall be determined
in accordance with Regulation 13D under the Securities Exchange Act of 1934, or any
similar successor regulation or rule; and the term "person" shall include any natural
person, corporation, partnership, trust or association, or any group or combination
thereof, whose ownership of Company securities would be required to be reported
under such Regulation 13D, or any similar successor regulation or rule.
(b) The Company ceases to be a reporting company pursuant to Section
13(a) of the Securities Exchange Act of 1934 or any similar successor provision.
(c) The number of the Company's Outside Directors, as defined herein, is
decreased by more than fifty percent (50%) in any twenty-five (25) month period or
the number of the Company's directors is increased such that the Outside Directors
constitute less than a majority of the Board.
(d) Within any twenty-five (25) month period, individuals who were
Outside Directors at the beginning of such period, together with any other Outside
Directors first elected as directors of the Company pursuant to nominations approved
or ratified by at least two-thirds (2/3) of the Outside Directors in office immediately
prior to such respective elections, cease to constitute a majority of the board of
directors of the Company.
(e) The Company is subject to a change in control which would require
reporting in response to Item 1 of Form 8-K under Regulation 13a-11 promulgated
under the Securities Exchange Act of 1934, as amended, or any similar successor
statute or rule, whether or not the Company is a reporting company under such Act.
(f) The Company's stockholders approve:
(i) any consolidation or merger of the Company in which the
Company is not the continuing or surviving corporation or pursuant to which
shares of Company common stock would be converted into cash, securities or
other property, other than a merger or consolidation of the Company in which
the holders of the Company's common stock immediately prior to the merger
or consolidation have substantially the same proportionate ownership and
voting control of the surviving corporation immediately after the merger or
consolidation; or
(ii) any sale, lease, exchange, liquidation or other transfer (in one
transaction or a series of transactions) of all or substantially all of the assets of
the Company.
Notwithstanding subparagraphs (i) and (ii) above, the term "Change in Control Event"
shall not include a consolidation, merger, or other reorganization if upon
consummation of such transaction all of the outstanding voting stock of the Company
is owned, directly or indirectly, by a holding company, and the holders of the
Company's common stock immediately prior to the transaction have substantially the
same proportionate ownership and voting control of the holding company.
6. Outside Directors. For purposes of this Agreement, an "Outside Director" as
of a given date shall mean a member of the Company's board of directors who has been
a director of the Company throughout the six (6) months prior to such date and who has
not been an employee of the Company at any time during such six (6) month period.
7. Notices. Any and all notices required or permitted to be given hereunder shall
be in writing and shall be deemed to have been given when deposited in the United States
mails, certified or registered mail, postage prepaid and addressed as follows:
To the Officer: Stephen A. Johnson
87 Dupont Drive
Presque Isle, Maine 04769-2920
To the Company: Maine Public Service Company
P. 0. Box 1209
Presque Isle, Maine 04769-1209
Either party may change by notice to the other the address to which notices to it are to be
addressed.
8. Applicable Law, Taxes, Binding Agreement, Severability, Construction.
(a) This Agreement shall be governed by and construed in accordance
with the laws of the State of Maine, except as to any matter which is preempted by
federal law.
(b) Notwithstanding anything to the contrary herein contained, the
Company may withhold from any amounts payable under this Agreement all federal,
state or other taxes or assessments which may be required by applicable statute or
regulation to be withheld.
(c) This Agreement shall be binding upon and inure to the benefit of the
Officer, his heirs, assigns, executors and legal representatives; and the Company, its
successors and assigns.
(d) If any provision of this Agreement shall be held invalid or
unenforceable by a court of competent jurisdiction, the remainder of this Agreement
shall not be affected thereby.
(e) The Outside Directors shall have the authority to construe and
interpret this Agreement on behalf of the Company, and any such determination by the
Outside Directors shall be conclusive on the Company.
9. Limitation on Amount to be Paid. If payment of any amount under this
Agreement would cause the Officer to be subject to an excise tax pursuant to Section
4999 of the Internal Revenue Code (as amended from time to time) or the regulations
thereunder, then such amount shall not be paid to the extent necessary to avoid the
imposition of such tax. The preceding sentence shall apply only if the aggregate
amount payable to the Officer or for his benefit under the Agreement, after payment of
such excise tax, would be less than the aggregate amount payable in accordance with
the preceding sentence.
10. Funding. This Agreement shall not be construed to create or require the
Company to create a trust or to otherwise act to fund the amounts payable hereunder.
11. Assignment. Except as required by law, the right to receive payments
hereunder shall not be subject to alienation, assignment, garnishment, attachment,
execution or levy of any kind, and any attempt to cause such payments to be so subject
shall not be recognized by the Company.
12. Execution of Further Documents. In the event the Officer receives
payments or benefits pursuant to the terms hereof and the Company's independent
counsel deems it necessary for the Company to receive a release or other
acknowledgment, the Officer agrees to execute any such document, as may be
reasonably required as a condition of his receipt of such payment or benefits.
13. Amendment and Waiver. The Agreement may be amended only in writing,
by the parties hereto, and no condition or provision of the Agreement may be waived
except in writing. Waiver by either party at any time of the other party's breach of, or
failure to comply with, any condition or provision of this Agreement to be performed
by such other party shall not be deemed a waiver of any other provision or condition at
the same time or of any provision or condition at any prior or subsequent time, unless
specifically stated therein.
14. Arbitration. In recognition of the mutual benefits of arbitration, the parties
hereby agree that arbitration as provided for herein shall be the exclusive remedy for
resolving any claim or dispute arising under this Agreement, and hereby mutually
waive any and all other remedies at law or in equity for determining any such claim or
dispute.
(a) Any arbitration under this Agreement, and any related judicial
proceeding, shall be initiated and shall proceed pursuant to the provisions of the
Maine Uniform Arbitration Act (the "Act") and, to the extent consistent with the
Act, the then prevailing rules of the American Arbitration Association (the
"Association") for labor and employment contracts. To initiate arbitration
hereunder, demand shall be given in writing to the Association and the other party
no later than one year after the claim arises. Any claim for which such demand is
not made within one year after the claim arises shall be barred and discharged
absolutely.
(b) Any arbitration under this Agreement shall be before a single
arbitrator, and an award in such arbitration may include only damages which the
arbitrator determines to be due under express provisions of this Agreement. The
arbitrator shall have no authority to award any other damages, including without
limitation, consequential and exemplary damages. Any award in arbitration shall
be subject to enforcement and appeal pursuant to the Act.
(c) The parties shall share equally all costs and fees charged by the
Association or the arbitrator.
15. No Additional Effect. Except as expressly provided herein, nothing
contained herein shall be construed to provide the Officer with any specific period of
employment, right to be retained in the service of the Company or other rights, nor
shall this Agreement be construed to otherwise limit the rights of the Company to
discharge or take other action with respect to the Officer.
IN WITNESS WHEREOF, the parties have executed this Agreement as of the day
and year first above written.
Witness: MAINE PUBLIC SERVICE COMPANY
/s/ Alice E. Shepard By /s/ Nathan L. Grass
Its Chairman, Executive Compensation
Committee
/s/ Marilyn Bouchard /s/ S. A. Johnson
Officer Stephen A. Johnson
Exhibit 10(p)
EMPLOYMENT CONTINUITY AGREEMENT
This Agreement made as of this 5th day of November, 1999, but effective
September 13, 1999, by and between MAINE PUBLIC SERVICE COMPANY, a
Maine corporation with its principal place of business in Presque Isle, Maine (the
"Company") and Larry E. LaPlante of Presque Isle, Maine, ("Officer").
WHEREAS, the Officer has been employed by the Company in a senior
management capacity for over 14 years, and is now its Vice President, Treasurer and
Chief Financial Officer; and
WHEREAS, the Officer's knowledge of the Company's affairs and his experience
are critical to the protection and enhancement of the best interests of the Company, its
employees, ratepayers and stockholders; and
WHEREAS, in the current business climate acquisitions of smaller, independently-operated utility companies is common; and
WHEREAS, the Company desires to assure itself of the continued employment of
the Officer and the benefit of his independent judgment in the operation of the
Company, particularly in the event that any such acquisition was being considered, in
light of the disruption resulting from such event;
WHEREAS, the Company and the Officer entered into an Employment Continuity
Agreement, dated May 9, 1989; and
WHEREAS, Section 14 of the Agreement provides that the Agreement may be
amended in writing by the parties; and
WHEREAS, the parties desire to amend and restate the Agreement as set forth
herein;
NOW, THEREFORE, in consideration of the mutual promises and undertakings
herein contained and for other good and valuable consideration, the receipt and
adequacy of which is acknowledged by each of the parties, the Officer and the
Company agree as follows:
1. Term of the Agreement and Renewal. The term of this Agreement shall be for a period beginning September 13, 1999, and ending December 31, 2001. On
January 1, 2002, and on January 1 of each period of three (3) years thereafter (in each
case such date to be a "Renewal Date") this Agreement automatically shall be renewed
for an additional three (3) year term, unless at least one (1) year prior to any such
Renewal Date, either party shall have given written notice to the other that such
renewal shall not take place. Such notice may be given by the Company only upon the
affirmative vote of the Compensation Committee of the Board of Directors.
2. Rights Upon Involuntary Termination of Employment. If, within twenty-four (24) months after the occurrence of a Change in Control Event, the Company
terminates the Officer's employment for any reason other than Good Cause as defined
in Paragraph 4, or if the Officer voluntarily terminates employment for Good Reason
as defined in Paragraph 3, the Company shall provide the Officer with the following:
(a) Within thirty (30) days of such termination, a lump sum cash
payment in an amount equal to the sum of:
(i) two hundred percent (200%) of the Officer's annual base
salary in effect upon the date of the Change in Control Event, and
(ii) two hundred percent (200%) of the award the Officer would
have received for the year in which such termination occurs, pursuant to the
Maine Public Service Company Incentive Compensation Plan, assuming
that his employment had not terminated and that for such year all applicable
performance goals will be met.
(b) The continuation of the Officer's participation and the participation
of his dependents (to the extent they were participating prior to his termination of
employment) in the Company's health, life, disability and other employee benefit
plans, programs and arrangements (excluding the Maine Public Service Company
Pension Plan and the Maine Public Service Company Non-Union Retirement
Savings Plan) for a period of twenty-four (24) months after such termination as if
he were still employed during such period; provided, however, if such participation
in any such plan, program or arrangement is specifically prohibited by the terms
thereof, the Company shall provide the Officer (and his dependents) with benefits
substantially similar to those which he was entitled to receive under such plan,
program or arrangement immediately prior to his termination of employment.
Additionally, at the end of any period of such coverage, the Officer shall have the
right to have assigned to him, for the cash surrender value thereof, any assignable
insurance owned by the Company on the life of the Officer. For purposes of this
Paragraph 2(b), any employee benefit determined with reference to the Officer's
compensation or earnings shall be based on his annual base salary unless otherwise
provided under the terms of the applicable employee benefit plan, program or
arrangement.
(c) The Company shall pay the Officer an amount equal to the award he
would have been entitled to receive under the Company's Incentive Compensation
Plan, if his employment had not terminated, based on the base salary he had earned
as of his termination date, and assuming that for such year all applicable
performance goals will be met. Such payment shall be made within ninety (90)
days after his employment terminates.
3. Termination for Good Reason. For purposes of this Agreement,
termination by the Officer of his employment for "Good Reason," except upon the
Officer's express written consent otherwise, shall mean:
(a) the assignment of duties to the Officer which:
(i) are materially different from his duties immediately prior to the
Change in Control Event, or
(ii) result in his having significantly less authority or responsibility
than he had prior to the Change in Control Event; or
(b) the Officer's removal from, or any failure to re-elect him to, any
position he held immediately prior to the Change in Control Event with either the
Company or any majority-owned subsidiary; or
(c) a reduction of the Officer's annual base salary in effect on the date of
the Change in Control Event or as the same may be increased from time to time
thereafter; or
(d) the Company's transferring or assigning the Officer to a place of
employment more than twenty-five (25) miles from Presque Isle, Maine, except for
required business travel to an extent substantially consistent with his business travel
obligations immediately prior to the Change in Control Event; or
(e) the Company's failure to provide the Officer with substantially the
same health, life and other employee benefit plans, programs and arrangements
(specifically including the Company's compensation and incentive plans, as the same
may be amended in the future), and substantially the same perquisites of employment,
as provided to him immediately prior to the Change in Control Event or as the same
may be increased thereafter; or
(f) the Company's failure to provide the Officer with substantially the
same support staff as provided to him immediately prior to the Change in Control
Event; or
(g) the Company's failure to increase the Officer's salary, employee
benefits or perquisites of employment in a manner or amount commensurate with
increases provided to the Company's other executive officers; or
(h) the Company's failure to obtain from any successor a satisfactory
agreement to assume and perform the terms of this Agreement.
4. Termination by Reason of Death or for Good Cause. Notwithstanding any
provision of this Agreement to the contrary, no benefits are payable hereunder upon the
Officer's death prior to his involuntary termination of employment pursuant to Paragraph
2 or voluntary termination of employment for Good Reason pursuant to Paragraph 3. The
Company retains the right to terminate the Officer for "Good Cause," in which event he
shall not be entitled to receive any payment or benefits pursuant to this Agreement. "Good
Cause" shall mean:
(a) the Officer's conviction, by a court of competent jurisdiction, of a crime
adversely reflecting on his honesty, trustworthiness or fitness to carry out the
responsibilities of his position with the Company in other respects; or
(b) a willful breach by him of any material duty or obligation imposed
upon him under the terms of his employment, as those terms existed immediately prior
to any Change in Control Event, and his failure to cure such breach within thirty (30)
days after receiving notice thereof from the Company.
5. "Change in Control Event." Each of the following events shall constitute a
"Change in Control Event" for purposes of this Agreement:
(a) Any person acquires beneficial ownership of Company securities and
is or thereby becomes a beneficial owner of securities entitling such person to exercise
twenty-five percent (25%) or more of the combined voting power of the Company's
then outstanding stock.
For purposes of this Agreement, "beneficial ownership" shall be determined
in accordance with Regulation 13D under the Securities Exchange Act of 1934, or any
similar successor regulation or rule; and the term "person" shall include any natural
person, corporation, partnership, trust or association, or any group or combination
thereof, whose ownership of Company securities would be required to be reported
under such Regulation 13D, or any similar successor regulation or rule.
(b) The Company ceases to be a reporting company pursuant to Section
13(a) of the Securities Exchange Act of 1934 or any similar successor provision.
(c) The number of the Company's Outside Directors, as defined herein, is
decreased by more than fifty percent (50%) in any twenty-five (25) month period or
the number of the Company's directors is increased such that the Outside Directors
constitute less than a majority of the Board.
(d) Within any twenty-five (25) month period, individuals who were
Outside Directors at the beginning of such period, together with any other Outside
Directors first elected as directors of the Company pursuant to nominations approved
or ratified by at least two-thirds (2/3) of the Outside Directors in office immediately
prior to such respective elections, cease to constitute a majority of the board of
directors of the Company.
(e) The Company is subject to a change in control which would require
reporting in response to Item 1 of Form 8-K under Regulation 13a-11 promulgated
under the Securities Exchange Act of 1934, as amended, or any similar successor
statute or rule, whether or not the Company is a reporting company under such Act.
(f) The Company's stockholders approve:
(i) any consolidation or merger of the Company in which the
Company is not the continuing or surviving corporation or pursuant to which
shares of Company common stock would be converted into cash, securities or
other property, other than a merger or consolidation of the Company in which
the holders of the Company's common stock immediately prior to the merger
or consolidation have substantially the same proportionate ownership and
voting control of the surviving corporation immediately after the merger or
consolidation; or
(ii) any sale, lease, exchange, liquidation or other transfer (in one
transaction or a series of transactions) of all or substantially all of the assets of
the Company.
Notwithstanding subparagraphs (i) and (ii) above, the term "Change in Control Event"
shall not include a consolidation, merger, or other reorganization if upon
consummation of such transaction all of the outstanding voting stock of the Company
is owned, directly or indirectly, by a holding company, and the holders of the
Company's common stock immediately prior to the transaction have substantially the
same proportionate ownership and voting control of the holding company.
6. Outside Directors. For purposes of this Agreement, an "Outside Director" as
of a given date shall mean a member of the Company's board of directors who has been
a director of the Company throughout the six (6) months prior to such date and who has
not been an employee of the Company at any time during such six (6) month period.
7. Notices. Any and all notices required or permitted to be given hereunder shall
be in writing and shall be deemed to have been given when deposited in the United States
mails, certified or registered mail, postage prepaid and addressed as follows:
To the Officer: Larry E. LaPlante
125 Fleetwood Street
Presque Isle, Maine 04769-3031
To the Company: Maine Public Service Company
P. 0. Box 1209
Presque Isle, Maine 04769-1209
Either party may change by notice to the other the address to which notices to it are to be
addressed.
8. Applicable Law, Taxes, Binding Agreement, Severability, Construction.
(a) This Agreement shall be governed by and construed in accordance with
the laws of the State of Maine, except as to any matter which is preempted by federal
law.
(b) Notwithstanding anything to the contrary herein contained, the
Company may withhold from any amounts payable under this Agreement all federal,
state or other taxes or assessments which may be required by applicable statute or
regulation to be withheld.
(c) This Agreement shall be binding upon and inure to the benefit of the
Officer, his heirs, assigns, executors and legal representatives; and the Company, its
successors and assigns.
(d) If any provision of this Agreement shall be held invalid or
unenforceable by a court of competent jurisdiction, the remainder of this Agreement
shall not be affected thereby.
(e) The Outside Directors shall have the authority to construe and interpret
this Agreement on behalf of the Company, and any such determination by the Outside
Directors shall be conclusive on the Company.
9. Limitation on Amount to be Paid. If payment of any amount under this
Agreement would cause the Officer to be subject to an excise tax pursuant to Section 4999
of the Internal Revenue Code (as amended from time to time) or the regulations
thereunder, then such amount shall not be paid to the extent necessary to avoid the
imposition of such tax. The preceding sentence shall apply only if the aggregate amount
payable to the Officer or for his benefit under the Agreement, after payment of such excise
tax, would be less than the aggregate amount payable in accordance with the preceding
sentence.
10. Funding. This Agreement shall not be construed to create or require the
Company to create a trust or to otherwise act to fund the amounts payable hereunder.
11. Assignment. Except as required by law, the right to receive payments
hereunder shall not be subject to alienation, assignment, garnishment, attachment,
execution or levy of any kind, and any attempt to cause such payments to be so subject
shall not be recognized by the Company.
12. Execution of Further Documents. In the event the Officer receives payments
or benefits pursuant to the terms hereof and the Company's independent counsel deems
it necessary for the Company to receive a release or other acknowledgment, the Officer
agrees to execute any such document, as may be reasonably required as a condition of his
receipt of such payment or benefits.
13. Amendment and Waiver. The Agreement may be amended only in writing, by
the parties hereto, and no condition or provision of the Agreement may be waived except
in writing. Waiver by either party at any time of the other party's breach of, or failure to
comply with, any condition or provision of this Agreement to be performed by such other
party shall not be deemed a waiver of any other provision or condition at the same time
or of any provision or condition at any prior or subsequent time, unless specifically stated
therein.
14. Arbitration. In recognition of the mutual benefits of arbitration, the parties
hereby agree that arbitration as provided for herein shall be the exclusive remedy for
resolving any claim or dispute arising under this Agreement, and hereby mutually waive
any and all other remedies at law or in equity for determining any such claim or dispute.
(a) Any arbitration under this Agreement, and any related judicial
proceeding, shall be initiated and shall proceed pursuant to the provisions of the Maine
Uniform Arbitration Act (the "Act") and, to the extent consistent with the Act, the then
prevailing rules of the American Arbitration Association (the "Association") for labor
and employment contracts. To initiate arbitration hereunder, demand shall be given
in writing to the Association and the other party no later than one year after the claim
arises. Any claim for which such demand is not made within one year after the claim
arises shall be barred and discharged absolutely.
(b) Any arbitration under this Agreement shall be before a single arbitrator,
and an award in such arbitration may include only damages which the arbitrator
determines to be due under express provisions of this Agreement. The arbitrator shall
have no authority to award any other damages, including without limitation,
consequential and exemplary damages. Any award in arbitration shall be subject to
enforcement and appeal pursuant to the Act.
(c) The parties shall share equally all costs and fees charged by the
Association or the arbitrator.
15. No Additional Effect. Except as expressly provided herein, nothing contained
herein shall be construed to provide the Officer with any specific period of employment,
right to be retained in the service of the Company or other rights, nor shall this Agreement
be construed to otherwise limit the rights of the Company to discharge or take other action
with respect to the Officer.
IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and
year first above written.
Witness: MAINE PUBLIC SERVICE COMPANY
/s/ Alice E. Shepard By /s/ Nathan L. Grass
Its Chairman, Executive Compensation
Committee
/s/ Marilyn Bouchard /s/ L. E. LaPlante
Officer Larry E. LaPlante
Exhibit 10(q)
EMPLOYMENT CONTINUITY AGREEMENT
This Agreement made as of this 5th day of November, 1999, but effective
September 13, 1999, by and between MAINE PUBLIC SERVICE COMPANY, a Maine
corporation with its principal place of business in Presque Isle, Maine (the "Company")
and William L. Cyr of Presque Isle, Maine, ("Officer").
WHEREAS, the Officer has been employed by the Company in a management
capacity for over 3 years, and is now its Assistant Vice President, Power Delivery; and
WHEREAS, the Officer's knowledge of the Company's affairs and his experience are
critical to the protection and enhancement of the best interests of the Company, its
employees, ratepayers and stockholders; and
WHEREAS, in the current business climate acquisitions of smaller, independently-operated utility companies is common; and
WHEREAS, the Company desires to assure itself of the continued employment of the
Officer and the benefit of his independent judgment in the operation of the Company,
particularly in the event that any such acquisition was being considered, in light of the
disruption resulting from such event;
NOW, THEREFORE, in consideration of the mutual promises and undertakings herein
contained and for other good and valuable consideration, the receipt and adequacy of
which is acknowledged by each of the parties, the Officer and the Company agree as
follows:
1. Term of the Agreement and Renewal. The term of this Agreement shall be for
a period beginning September 13, 1999, and ending December 31, 2001. On January 1,
2002, and on January 1 of each period of three (3) years thereafter (in each case such date
to be a "Renewal Date") this Agreement automatically shall be renewed for an additional
three (3) year term, unless at least one (1) year prior to any such Renewal Date, either
party shall have given written notice to the other that such renewal shall not take place.
Such notice may be given by the Company only upon the affirmative vote of the
Compensation Committee of the Board of Directors.
2. Rights Upon Involuntary Termination of Employment. If, within twenty-four
(24) months after the occurrence of a Change in Control Event, the Company terminates
the Officer's employment for any reason other than Good Cause as defined in Paragraph
4, or if the Officer voluntarily terminates employment for Good Reason as defined in
Paragraph 3, the Company shall provide the Officer with the following:
(a) Within thirty (30) days of such termination, a lump sum cash payment
in an amount equal to the sum of:
(i) two hundred percent (200%) of the Officer's annual base salary
in effect upon the date of the Change in Control Event, and
(ii) two hundred percent (200%) of the award the Officer would
have received for the year in which such termination occurs, pursuant to the
Maine Public Service Company Incentive Compensation Plan, assuming that
his employment had not terminated and that for such year all applicable
performance goals will be met.
(b) The continuation of the Officer's participation and the participation of
his dependents (to the extent they were participating prior to his termination of
employment) in the Company's health, life, disability and other employee benefit
plans, programs and arrangements (excluding the Maine Public Service Company
Pension Plan and the Maine Public Service Company Non-Union Retirement Savings
Plan) for a period of twenty-four (24) months after such termination as if he were still
employed during such period; provided, however, if such participation in any such
plan, program or arrangement is specifically prohibited by the terms thereof, the
Company shall provide the Officer (and his dependents) with benefits substantially
similar to those which he was entitled to receive under such plan, program or
arrangement immediately prior to his termination of employment. Additionally, at the
end of any period of such coverage, the Officer shall have the right to have assigned
to him, for the cash surrender value thereof, any assignable insurance owned by the
Company on the life of the Officer. For purposes of this Paragraph 2(b), any employee
benefit determined with reference to the Officer's compensation or earnings shall be
based on his annual base salary unless otherwise provided under the terms of the
applicable employee benefit plan, program or arrangement.
(c) The Company shall pay the Officer an amount equal to the award he
would have been entitled to receive under the Company's Incentive Compensation
Plan, if his employment had not terminated, based on the base salary he had earned as
of his termination date, and assuming that for such year all applicable performance
goals will be met. Such payment shall be made within ninety (90) days after his
employment terminates.
3. Termination for Good Reason. For purposes of this Agreement, termination
by the Officer of his employment for "Good Reason," except upon the Officer's
express written consent otherwise, shall mean:
(a) the assignment of duties to the Officer which:
(i) are materially different from his duties immediately prior to the
Change in Control Event, or
(ii) result in his having significantly less authority or responsibility
than he had prior to the Change in Control Event; or
(b) the Officer's removal from, or any failure to re-elect him to, any
position he held immediately prior to the Change in Control Event with either the
Company or any majority-owned subsidiary; or
(c) a reduction of the Officer's annual base salary in effect on the date of
the Change in Control Event or as the same may be increased from time to time
thereafter; or
(d) the Company's transferring or assigning the Officer to a place of
employment more than twenty-five (25) miles from Presque Isle, Maine, except for
required business travel to an extent substantially consistent with his business travel
obligations immediately prior to the Change in Control Event; or
(e) the Company's failure to provide the Officer with substantially the
same health, life and other employee benefit plans, programs and arrangements
(specifically including the Company's compensation and incentive plans, as the same
may be amended in the future), and substantially the same perquisites of employment,
as provided to him immediately prior to the Change in Control Event or as the same
may be increased thereafter; or
(f) the Company's failure to provide the Officer with substantially the
same support staff as provided to him immediately prior to the Change in Control
Event; or
(g) the Company's failure to increase the Officer's salary, employee
benefits or perquisites of employment in a manner or amount commensurate with
increases provided to the Company's other executive officers; or
(h) the Company's failure to obtain from any successor a satisfactory
agreement to assume and perform the terms of this Agreement.
4. Termination by Reason of Death or for Good Cause. Notwithstanding any
provision of this Agreement to the contrary, no benefits are payable hereunder upon the
Officer's death prior to his involuntary termination of employment pursuant to Paragraph
2 or voluntary termination of employment for Good Reason pursuant to Paragraph 3. The
Company retains the right to terminate the Officer for "Good Cause," in which event he
shall not be entitled to receive any payment or benefits pursuant to this Agreement. "Good
Cause" shall mean:
(a) the Officer's conviction, by a court of competent jurisdiction, of a crime
adversely reflecting on his honesty, trustworthiness or fitness to carry out the
responsibilities of his position with the Company in other respects; or
(b) a willful breach by him of any material duty or obligation imposed
upon him under the terms of his employment, as those terms existed immediately prior
to any Change in Control Event, and his failure to cure such breach within thirty (30)
days after receiving notice thereof from the Company.
5. "Change in Control Event." Each of the following events shall constitute a
"Change in Control Event" for purposes of this Agreement:
(a) Any person acquires beneficial ownership of Company securities and
is or thereby becomes a beneficial owner of securities entitling such person to exercise
twenty-five percent (25%) or more of the combined voting power of the Company's
then outstanding stock.
For purposes of this Agreement, "beneficial ownership" shall be determined
in accordance with Regulation 13D under the Securities Exchange Act of 1934, or any
similar successor regulation or rule; and the term "person" shall include any natural
person, corporation, partnership, trust or association, or any group or combination
thereof, whose ownership of Company securities would be required to be reported
under such Regulation 13D, or any similar successor regulation or rule.
(b) The Company ceases to be a reporting company pursuant to Section
13(a) of the Securities Exchange Act of 1934 or any similar successor provision.
(c) The number of the Company's Outside Directors, as defined herein, is
decreased by more than fifty percent (50%) in any twenty-five (25) month period or
the number of the Company's directors is increased such that the Outside Directors
constitute less than a majority of the Board.
(d) Within any twenty-five (25) month period, individuals who were
Outside Directors at the beginning of such period, together with any other Outside
Directors first elected as directors of the Company pursuant to nominations approved
or ratified by at least two-thirds (2/3) of the Outside Directors in office immediately
prior to such respective elections, cease to constitute a majority of the board of
directors of the Company.
(e) The Company is subject to a change in control which would require
reporting in response to Item 1 of Form 8-K under Regulation 13a-11 promulgated
under the Securities Exchange Act of 1934, as amended, or any similar successor
statute or rule, whether or not the Company is a reporting company under such Act.
(f) The Company's stockholders approve:
(i) any consolidation or merger of the Company in which the
Company is not the continuing or surviving corporation or pursuant to which
shares of Company common stock would be converted into cash, securities or
other property, other than a merger or consolidation of the Company in which
the holders of the Company's common stock immediately prior to the merger
or consolidation have substantially the same proportionate ownership and
voting control of the surviving corporation immediately after the merger or
consolidation; or
(ii) any sale, lease, exchange, liquidation or other transfer (in one
transaction or a series of transactions) of all or substantially all of the assets of
the Company.
Notwithstanding subparagraphs (i) and (ii) above, the term "Change in Control Event"
shall not include a consolidation, merger, or other reorganization if upon
consummation of such transaction all of the outstanding voting stock of the Company
is owned, directly or indirectly, by a holding company, and the holders of the
Company's common stock immediately prior to the transaction have substantially the
same proportionate ownership and voting control of the holding company.
6. Outside Directors. For purposes of this Agreement, an "Outside Director" as
of a given date shall mean a member of the Company's board of directors who has been
a director of the Company throughout the six (6) months prior to such date and who has
not been an employee of the Company at any time during such six (6) month period.
7. Notices. Any and all notices required or permitted to be given hereunder shall
be in writing and shall be deemed to have been given when deposited in the United States
mails, certified or registered mail, postage prepaid and addressed as follows:
To the Officer: William L. Cyr
P.O. Box 1881
Presque Isle, Maine 04769-1881
To the Company: Maine Public Service Company
P. 0. Box 1209
Presque Isle, Maine 04769-1209
Either party may change by notice to the other the address to which notices to it are to be
addressed.
8. Applicable Law, Taxes, Binding Agreement, Severability, Construction.
(a) This Agreement shall be governed by and construed in accordance with
the laws of the State of Maine, except as to any matter which is preempted by federal
law.
(b) Notwithstanding anything to the contrary herein contained, the
Company may withhold from any amounts payable under this Agreement all federal,
state or other taxes or assessments which may be required by applicable statute or
regulation to be withheld.
(c) This Agreement shall be binding upon and inure to the benefit of the
Officer, his heirs, assigns, executors and legal representatives; and the Company, its
successors and assigns.
(d) If any provision of this Agreement shall be held invalid or
unenforceable by a court of competent jurisdiction, the remainder of this Agreement
shall not be affected thereby.
(e) The Outside Directors shall have the authority to construe and interpret
this Agreement on behalf of the Company, and any such determination by the Outside
Directors shall be conclusive on the Company.
9. Limitation on Amount to be Paid. If payment of any amount under this
Agreement would cause the Officer to be subject to an excise tax pursuant to Section 4999
of the Internal Revenue Code (as amended from time to time) or the regulations
thereunder, then such amount shall not be paid to the extent necessary to avoid the
imposition of such tax. The preceding sentence shall apply only if the aggregate amount
payable to the Officer or for his benefit under the Agreement, after payment of such excise
tax, would be less than the aggregate amount payable in accordance with the preceding
sentence.
10. Funding. This Agreement shall not be construed to create or require the
Company to create a trust or to otherwise act to fund the amounts payable hereunder.
11. Assignment. Except as required by law, the right to receive payments
hereunder shall not be subject to alienation, assignment, garnishment, attachment,
execution or levy of any kind, and any attempt to cause such payments to be so subject
shall not be recognized by the Company.
12. Execution of Further Documents. In the event the Officer receives payments
or benefits pursuant to the terms hereof and the Company's independent counsel deems
it necessary for the Company to receive a release or other acknowledgment, the Officer
agrees to execute any such document, as may be reasonably required as a condition of his
receipt of such payment or benefits.
13. Amendment and Waiver. The Agreement may be amended only in writing, by
the parties hereto, and no condition or provision of the Agreement may be waived except
in writing. Waiver by either party at any time of the other party's breach of, or failure to
comply with, any condition or provision of this Agreement to be performed by such other
party shall not be deemed a waiver of any other provision or condition at the same time
or of any provision or condition at any prior or subsequent time, unless specifically stated
therein.
14. Arbitration. In recognition of the mutual benefits of arbitration, the parties
hereby agree that arbitration as provided for herein shall be the exclusive remedy for
resolving any claim or dispute arising under this Agreement, and hereby mutually waive
any and all other remedies at law or in equity for determining any such claim or dispute.
(a) Any arbitration under this Agreement, and any related judicial
proceeding, shall be initiated and shall proceed pursuant to the provisions of the Maine
Uniform Arbitration Act (the "Act") and, to the extent consistent with the Act, the then
prevailing rules of the American Arbitration Association (the "Association") for labor
and employment contracts. To initiate arbitration hereunder, demand shall be given
in writing to the Association and the other party no later than one year after the claim
arises. Any claim for which such demand is not made within one year after the claim
arises shall be barred and discharged absolutely.
(b) Any arbitration under this Agreement shall be before a single arbitrator,
and an award in such arbitration may include only damages which the arbitrator
determines to be due under express provisions of this Agreement. The arbitrator shall
have no authority to award any other damages, including without limitation,
consequential and exemplary damages. Any award in arbitration shall be subject to
enforcement and appeal pursuant to the Act.
(c) The parties shall share equally all costs and fees charged by the
Association or the arbitrator.
15. No Additional Effect. Except as expressly provided herein, nothing contained
herein shall be construed to provide the Officer with any specific period of employment,
right to be retained in the service of the Company or other rights, nor shall this Agreement
be construed to otherwise limit the rights of the Company to discharge or take other action
with respect to the Officer.
IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and
year first above written.
Witness: MAINE PUBLIC SERVICE COMPANY
/s/ Alice E. Shepard By /s/ Nathan L. Grass
Its Chairman, Executive Compensation
Committee
/s/ Paul R. Cariani /s/ William L. Cyr
Officer William L. Cyr
Exhibit 13
Maine Public Service Company
1999 Annual Report
We put a lot of energy into Northern Maine
(Inside Cover)
The primary goal of Maine Public Service Company is to provide reliable,
economical electrical power to Northern Maine. The Company is an investor-owned electric utility with two wholly-owned subsidiaries, Maine and New
Brunswick Electrical Power Company, Ltd., (Maine and New Brunswick)
located at Tinker, New Brunswick, and Energy Atlantic, LLC (EA). It was a
year of transition as the Company, on June 8, 1999, sold all generating assets,
including the generating assets of Maine and New Brunswick as required under
Maine's electric utility restructuring law. EA formally began operation in
January, 1999 as the Company's unregulated marketing subsidiary and has
begun providing electricity to retail customers in Maine effective March 1,
2000. Maine Public Service Company is committed to continue highly reliable
service and delivery of energy to more than 35,000 retail customers in a 3,600
square mile service territory, at the lowest possible cost, while meeting the
challenges of restructuring.
During 1999, Maine Public Service Company had a favorable mixture of
energy 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.
Table of Contents
Profile and Table of Contents Inside Front Cover
President's Letter 1-2
Energy Atlantic at A Glance 3-5
Analysis of Financial Condition
and Review of Operations -- 1999 6-15
Shareholder Information 15-16
Five-Year Summary of Selected Financial Data 16
Report of Independent Accountants 17
Financial Statements and Notes 18-35
Consolidated Financial Statistics 36-37
Consolidated Operating Statistics 38-39
Directors 40
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.mainepublicservice.com
E-Mail: mainepub@ mfx.net
(Photo)
Construction crews string new conductor to upgrade electrical system -- Maine Public
Service Company's primary focus is on excellence in its regulated distribution business. In
today's newly restructured utility environment, MPS continues to deliver electricity, maintain
poles and wires, read meters, and answer customers' calls for assistance.
(Page 1-2)
President's Letter
to our Shareholders and
Employees
(Photo)
I am pleased to report that 1999 was an excellent year for your Company.
Earnings were $2.48 per share versus $1.39 in 1998. This amount includes
$.24 per share related to a tax benefit from the sale of generating assets.
Without this one-time benefit, 1999 earnings would have been $2.24.
Due to our strong financial performance, we were able to increase the
annual dividend from $1.00 to $1.20 on October 1, 1999. In addition to being
a very profitable year, compared to recent years, 1999 was perhaps the most
eventful year in the Company's history. Among our accomplishments, we
completed the sale of our generating assets, successfully entered the new
millennium without any Y2K related problems, and stipulated with the Maine
Public Utilities Commission (MPUC) for transmission and distribution rates
and stranded cost recovery beginning March 1, 2000. The success of Y2K can
be attributed to the preparation and farsightedness of our employees.
A lot of planning and commitment of resources has gone into the
preparation for restructuring and customer choice on March 1, 2000. The
stipulation with the MPUC allows for a 10.7% return on equity based upon
capitalization with a 51% equity ratio. We intend to use the proceeds from our
generating asset sale to reduce debt and, as a result, our equity ratio will
exceed 51% without further action on our part. Therefore, in order to reduce
the equity ratio we have entered into a Common Stock Buyback Program,
authorized by the MPUC, for up to 500,000 shares over a five-year period.
Energy Atlantic, LLC (EA), our unregulated power marketing subsidiary,
has exceeded our expectations in its first year of operation and was awarded
Standard Offer Service (SOS) for all residential and small non-residential
customers in Central Maine Power Company's (CMP) Service territory for the
two years beginning March 1, 2000. SOS is for customers who are unable or
do not wish to choose a Competitive Electricity Provider (CEP). EA will
supply power to approximately 525,000 customers with estimated sales of 3.2
million MWH. Although profit margins are small, SOS will provide EA with
a solid customer base over the next two years and a foundation in which to
develop the business. At a minimum, we believe that the profits from SOS will
be sufficient to make EA self-supporting over the next two years. The
competitive electric supply market has been slow to develop in Maine as well
as other New England states, but we are hopeful that as the market matures EA
will be well-positioned to be competitive and share in that market. EA entered
into an agreement with Engage Energy, US, L.P. as its wholesale supplier, and
our success in the competitive bidding process for SOS is certainly an
indication of our ability to compete in a State-wide market.
Despite our accomplishments for the year, our stock did not perform as well
as I had hoped. Nevertheless, MPS stock appreciated approximately 13.9%
(exclusive of dividends) during 1999 and was one of the better performers in
the Electric Utility Group as a whole compared to the majority of Electric
Utility Stocks, which declined in 1999. The positive developments in 1999,
such as the encouraging progress of EA, the completion of the profitable sale
of our generation assets, and the sound financial health of the Company, will
hopefully further benefit our shareholders in the new millennium.
We believe our future is bright with the regulated T&D Company operating
efficiently in an economy that has improved each and every year since the
closing of Loring Air Force Base. A major expansion was completed by
McCain Foods, our largest customer, that is very helpful to the agricultural
sector of our economy. The Loring Commerce Centre continues to attract new
businesses, and we continue to work with all communities in our territory in
pursuit of economic development.
As always, I appreciate your confidence and support and give full credit to
our customers and employees for making this the banner year that it was.
Sincerely,
Paul R. Cariani
President and CEO
(Page 3)
Energy Atlantic ... Maine's Only Locally
Owned and
Operated
Competitive
Electricity Supplier
The Changing Energy Marketplace
Energy Atlantic strongly supports deregulation of the electric power industry
and welcomes an unregulated wholesale and retail energy marketplace in
Maine. Energy Atlantic was established to give the consumers of Maine the
power of choice when it comes to their electricity supplier, providing Maine
people the option to keep money and jobs in Maine by choosing a LOCAL
competitive provider. Currently, Energy Atlantic is the only Maine owned and
operated competitive electricity supplier licensed by the Maine Public Utilities
Commission (MPUC).
Energy Atlantic at A Glance
- Wholly-owned subsidiary of Maine Public Service Company (MPS)
- Headquartered in Presque Isle, Maine
- Twelve Employees
- Serving residential, commercial and industrial customers throughout the
State of Maine
- 1999 Gross Wholesale Profits of $597,000, which partially offset the start-up
costs
- Starting March 1, 2000, as the CMP Residential and Small Non-Residential
Standard Offer Service Provider, Energy Atlantic will be the largest
competitive supplier in Maine and one of the largest in New England. This
arrangement is expected to generate net income in 2000, which is earlier
than originally anticipated.
Energy Atlantic as an Electricity Supplier
Energy Atlantic is a new and progressive company strongly positioned to take
advantage of the emerging trends in Maine's deregulated electricity market.
1999 was spent laying the foundation and building the infrastructure to make
Energy Atlantic the preeminent competitive supplier in Maine. Our goal is to
provide customers with exceptional customer service and the most competitive
energy supply price on a consistent basis.
Winner of Standard Offer for Residential and Small Non-Residential
customer class in Central Maine Power Company's territory.
Starting March 1, 2000, Energy Atlantic became the standard offer provider to
almost 525,000 customers in southern and central Maine through February
2002. Energy Atlantic also received 20% of the Standard Offer Service for the
medium commercial and industrial class in . . .
(Photo)
The Faces of
Energy Atlantic
Standing:
Annette N. Arribas, Marketing Manager;
Donald J. Theriault, Forecast Analyst;
Tim D. Brown, Pricing Manager;
Calvin D. Deschene, Director;
Barry E. Bartley, Account Executive;
Tim K. Charette, Energy Manager;
Lisa A. Wilcox, Customer Service Representative;
Seated:
C. Nan Carmichael, Customer Service Supervisor;
Terry C. Umphrey, Information Technology Manager;
Janis D. Currier, Administrative Assistant;
Not shown:
Michael W. Parquette, Account Executive
Stanley L. Baker, Information Systems Analyst
(Logo)
(Page 4)
. . . Maine Public Service Company's territory. The Maine Public Utilities
Commission awarded both these contracts to Energy Atlantic.
Retail Sales
Prior to March 1, 2000, Energy Atlantic successfully signed retail contracts
with individual customers for annual sales of 150,000 megawatt-hours
throughout the State of Maine. Our focus for the remainder of 2000 will be to
increase our retail sales, signing new customers at our location in the
Aroostook Centre Mall, through our call center, and through the efforts of our
Account Executives throughout Maine.
Behind The
Scenes
Infrastructure Development
In forming Energy Atlantic, we have a unique
opportunity to create a model
energy services company for the State of Maine and beyond - and we are
putting in place the infrastructure to support it. We have selected ICF Energy
Vision 2000 (EV2K) software as our operating and reporting system. EV2K is
a state-of-the-art web-based computer system, with integrated modules for
forecasting, load profiling, settlement, accounts receivable, billing and
customer information. By binding together all the company's key functions,
our customer service capabilities are greatly enhanced.
In November 1999 Energy Atlantic passed all its EDI testing and received
certification from Central Maine Power as an energy provider for Standard
Offer Service. Full certification from CMP for retail business was acquired on
December 24, 1999, making Energy Atlantic the first competitive supplier in
the State to achieve this status. Certification for MPS followed in January
2000, with Bangor Hydro planning to do their certifications in early summer.
We have also established an in-house customer care center, ensuring the
quality of service provided to our clients and prospective clients. We are
committed to building long-term, mutually beneficial relationships and the first
step in this process is providing prompt, knowledgeable and quality customer
service and support.
Exclusive Supply Arrangement
In order to provide Energy Atlantic with a reliable, competitive source of
supply of electricity for resale in the open marketplace, we have signed a
wholesale power agreement with Engage Energy, US, L.P., exclusive to both
us and to Engage. This agreement also provides us with much of the risk
management necessary to operate successfully in a competitive market.
(Three Captioned Photos)
Keeping money and jobs in Maine is important to me.
Let's talk seriously about choice.
I think buying locally is important.
Do you think these people care where their power comes from?
You bet they do ... and so should you. In fact, everyone should under Maine's
newly deregulated electrical industry. That's because only one electricity
supply company is Maine owned and operated . . . Energy Atlantic.
(Logo)
(Page 5)
Wholesale Sales
During 1999, the wholesale function played an important role at Energy
Atlantic, producing a gross wholesale profit of approximately $597,000. This
success allowed us to offset a portion of the costs associated with the
establishment of our new company.
More recently, our focus has been the development of our retail business.
With the awarding of the standard offer contract in CMP territory, as well as
increasing retail sales, our wholesale team is responsible for coordination of
the information flow between Engage Energy and Energy Atlantic, as well as
forecasting, scheduling and tagging of energy transactions.
Marketing
Our marketing objective for 1999 was to "brand" the Energy Atlantic name
throughout the entire State as the only local choice for an energy supplier. By
emphasizing our status as the only Maine owned and operated electricity
supplier in the State, our messaging establishes Energy Atlantic as a trusted,
knowledgeable educational resource for consumers during the transition and
beyond.
An intensive branding/advertising campaign took place across the state during
October and November of 1999, making Energy Atlantic a well-known name in
Maine. In addition, the company has enjoyed a variety of positive editorial
publicity from the largest and most respected newspapers, TV and radio
stations in Maine.
With the goal of making Energy Atlantic the most visible energy marketer in
Maine, the Marketing and Account Executive staff have and will continue to
attend a wide range of trade shows across the State. By participating in a
variety of educational seminars and Public forums, and having Account
Executives in the field on a daily basis, Energy Atlantic has taken a leadership
role and is building a reputation of reliability and Service excellence.
(Photo)
Visit Us at the Mall!
In selecting a location for our headquarters, we considered
a variety of
factors. Among these were convenience for our new customers, visibility to
the public and a satisfying working atmosphere for our staff. We believe we
achieved our objectives at our newly remodeled office at the Aroostook Centre
Mall in Presque Isle. Our front lobby area has been transformed into a
professional customer service center, and we welcome everyone to stop by
and experience our friendly, local service. As the market develops further we
also plan to open branch facilities in southern and central Maine.
In Conclusion
Charting a course in Maine's newly restructured market is a challenge to
which Energy Atlantic has unhesitatingly risen. We are putting the resources
in place to make this journey a success - one that brings long-term value to
you, our shareholders.
Contact Us
By Phone: 1-888-373-7911
By e-mail: energy@energyatlantic.com
By Mail: PO Box 1148
Presque Isle, Me 04769-1148
Our Web Address: www.energyatlantic.com
(Page 6)
Analysis of Financial Condition and Review of
Operations - 1999
RESULTS OF OPERATIONS
Operating Revenues and Energy Sales
Consolidated operating revenues and MWH sales for the years 1999, 1998,
and 1997 are as follows:
Consolidated Operating Revenues and Megawatt Hours Sold
1999 1998 1997
Dollars MWH Dollars MWH Dollars MWH
Residential $ 21,708 170,481 $ 20,593 163,073 $ 20,391 167,368
Commercial & Industrial
- Large 10,596 149,979 10,249 144,228 9,452 134,741
Commercial & Industrial
- Small 19,462 183,424 18,363 173,168 17,419 168,976
Other Retail 1,249 7,477 1,340 10,006 1,468 13,323
Total Retail 53,015 511,361 50,545 490,475 48,730 484,408
Sales for Resale 1,551 42,224 1,893 56,013 2,168 57,578
Total Primary 54,566 553,585 52,438 546,488 50,898 541,986
Secondary Sales 10,985 348,363 2,337 67,380 2,140 52,648
Total Sales of Electricity 65,551 901,948 54,775 613,868 53,038 594,634
Other 1,905 1,852 2,034
Total Operating Revenues $ 67,456 $ 56,627 $ 55,072
Primary sales for 1999 were 553,585 MWH,
approximately 1.3% and 2.1% higher than
primary sales in 1998 and 1997, respectively. The retail sales component was 511,361 MWH,
which was 20,886 MWH (4.3%) higher than 1998 and 26,953 MWH (5.6%) higher than 1997. In
preparation for retail competition beginning on March 1, 2000, the Company converted all
residential customers to monthly meter reading, while the majority had previously been read bi-monthly. Therefore, the conversion to monthly meter reading for residential customers
accounted for the 7,408 MWH (4.5%) increase in 1999 residential sales and the 3,113 MWH
(1.9%) increase compared to 1997. Unbilled revenues, recorded as other revenues to recognize
electric service delivered but not billed as of December 31, 1999, decreased correspondingly.
Large commercial and industrial sales increased by 5,751 MWH (4.0%) and 15,238 MWH
(11.3%) in 1999 over 1998 and 1997, respectively, 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 183,424 MWH in 1999, an increase of 10,256 MWH (5.9%) and 14,448
MWH (8.6%) over sales in 1998 and 1997, respectively, primarily due to the utilization of the
former Loring Air Force Base by small commercial customers. Other retail sales in 1999 were
7,477 MWH, a decrease of 2,529 MWH and 5,846 MWH from 1998 and 1997, respectively, as a
result of the aforementioned re-utilization of the former Loring AFB. The sales for resale were
42,224 MWH in 1999, a 13,789 MWH (24.6%) decrease compared to 1998 with the termination
of sales to Perth-Andover Light and Power as of the June 8, 1999 sale of the Company's
generating assets.
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 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 1999 of $10,985,000 were $8,648,000 higher than sales in 1998, reflecting
the wholesale power marketing activity of Energy Atlantic, LLC (EA), the Company's unregulated
marketing subsidiary. EA formally began operation in January, 1999 and had sales of $8,429,000.
The remainder of the increase reflects the sale of all of the Company's entitlement to Wyman Unit
No. 4, when available, for varying lengths of time at existing market rates. After June 8, 1999 when
the Company sold its generating assets, including Wyman, the Company began to purchase Wyman
energy and continued the secondary sales.
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 and subsequently approved increases of 4.4%, 2.9%
and 3.9% effective January 1, 1996, February 1, 1997 and February 1, 1998, respectively. For the
final year of the rate plan, the MPUC approved a stipulation allowing a 3.66% specified rate increase
as of April 1, 1999. Rather than increase customer rates, the MPUC allowed the recognition of these
revenues as an offset to the available value from the sale of the generating assets. The 3.66%
increase totaled $1,316,000 in 1999 and has been recorded as other revenue, where it was partially
offset by a $949,000 decrease in unbilled revenue because of the transition to residential monthly
meter reading, as previously mentioned.
(Page 7)
The Federal Energy Regulatory Commission (FERC) has jurisdiction over US wholesale rates,
included as sales for resale in the previous table and discussion.
Energy
Supply
The Company's sources of energy changed significantly with the June 8, 1999 sale of the
generating assets, as more fully explained in the "Regulatory Proceedings - Generating Asset Sale"
section of this Annual Report, and the increased purchases to supply Energy Atlantic's (EA) power
marketing activity. As reflected in the table below, the Company ceased its oil-fired and hydro
generation on June 8, 1999, however, these sources accounted for 3.0% and 8.6%, respectively, of
the total energy supply in 1999. In 1998, the last full year of generating asset ownership, oil-fired
and hydro generation accounted for 5.4% and 18.8% of the supply, respectively. After the asset sale,
the Company's sources of energy were purchases from a 17.6 MW wood-burning independent power
producer, currently owned by Wheelabrator-Sherman (W-S) and several other suppliers, primarily
Northeast Empire in Ashland, Maine, NB Power, and WPS-PDI, the purchaser of the Company's
assets.
Electric Output By Sources
(Percent)
1999 1998 1997
Oil 3.0 5.4 4.2
Cogeneration 13.7 19.5 19.8
Purchases 74.7 56.3 58.9
Hydro 8.6 18.8 17.1
Total 100.0 100.0 100.0
In 1986, under an agreement ordered by the MPUC, the Company began purchasing output from
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
13.7% of the Company's energy supply in 1999 compared to 19.5% and 19.8% in 1998 and 1997,
respectively.
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. Maine Yankee has not operated since December, 1996. To offset
the loss of Maine Yankee production, the Company purchased replacement energy from various
sources, including, but not limited to, NB Power, in 1997, on a competitive basis. Beginning in
February, 1998, Maine Yankee replacement energy was purchased from Northeast Empire from its
facility in Ashland, Maine, in accordance with an agreement signed on December 19, 1997 that was
effective until March 1, 2000. These purchases, along with EA's power marketing purchases from
various suppliers beginning in 1999, accounted for 74.7%, 56.3% and 58.9% of the Company's
energy supply in 1999, 1998 and 1997, respectively.
Operating Expenses
For the three-year period 1997-1999, purchased power and other operation and maintenance
expenses are as follows:
(Dollars in Thousands)
1999 1998 1997
Purchased Power
Wheelabrator-Sherman $14,205 $13,830 $15,911
Maine Yankee 3,760 5,670 12,303
Northeast Empire 7,768 7,160 --
NB Power 3,585 4,562 10,786
WPS-PDI 2,653 -- --
System Purchases 60 530 1,308
Power Marketing 8,645 -- --
Total Purchased Power 40,676 31,752 40,308
Deferred Fuel (1,603) (2,234) (3,699)
Net Purchased Power $ 39,073 $ 29,518 $ 36,609
Generation
Fuel Expense $ 622 $ 896 $ 893
Other 569 1,237 1,321
Total Generation 1,191 2,133 2,214
Transmission and
Distribution 3,008 3,614 3,609
Customer Accounting and
General Administrative 7,276 7,221 6,947
Energy Atlantic 1,037 -- --
Other Oper. & Maint. $12,512 $12,968 $12,770
As reflected in the table above, net purchased power for 1999 was
$39,073,000, an increase of
$9,555,000 over 1998 due primarily to the power marketing activity of the Company's unregulated
marketing subsidiary, Energy Atlantic (EA). EA's purchases accounted for $7,324,000 of the
increase. In addition, as more fully explained in the "Regulatory Proceedings - Generating Asset
Sale" section of this Annual Report, the Company purchased energy produced by facilities bought
from the Company by WPS-PDI on June 8, 1999, under a buy-back agreement. These purchases from
WPS-PDI amounted to $2,653,000 in 1999, while prior to the asset sale, the fuel and operating
expenses of the facilities were classified as generation expenses. Net purchase power expenses
decreased by $7,091,000 from 1997 to 1998 reflecting efforts in 1997 to restart Maine Yankee prior
to the decision to close the plant and a $1.5 million MPUC stipulated write-off of deferred capacity
charges in 1997 for Maine Yankee refueling expenses. Wheelabrator-Sherman (W-S) power
purchases were $14,205,000, a $375,000 or a 2.7% increase from 1998 because of a 1.3% increase
in output and a contractual price increase in 1999. For more information on the W-S agreement, see
the "Regulatory Proceedings - Restructured Agreement with Wheelabrator-Sherman" section of this
Annual Report. For 1999, 1998, and 1997, these mandated purchases from W-S represented 34.9%,
43.6%, and 39.5%, respectively, of total purchased power expenses. Maine Yankee expenses were
$3,760,000 in 1999, a decrease of $1,910,000 compared to 1998 reflecting higher decommissioning
expenses in 1998, an insurance refund in 1999 due to the curtailment of operations, and a FERC rate
stipulation approved in early 1999. For additional information, see the "Maine Yankee" section of
this Annual Report. The Company purchased replacement energy primarily from NB Power in 1997
and, as discussed in the "Energy Supply" section of this Annual Report, began to also purchase
Maine Yankee replacement power from Northeast Empire in Ashland, Maine, in February 1998.
Purchases in 1999 from NB Power and Northeast Empire totaled $11,353,000, a decrease of $369,000
from 1998. System purchases were $60,000 in 1999, a decrease of $470,000 and $1,248,000 from
1998 and 1997, respectively, because of the availability of other sources of power discussed above.
Deferred fuel expense, a component of purchased power, was a negative $1,603,000 in 1999,
compared to a negative $2,234,000 and a negative $3,699,000 in 1998 and 1997, respectively.
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 purchase power agreement with W-S. The sharing
mechanism for the Maine Yankee replacement power went into effect on June 6, 1997, with
approximately $3.0 million deferred through the end of 1999, subject to future collection. In 1999,
as part of a rate stipulation, the Company agreed to amortize previously deferred Maine Yankee
replacement power costs with $1.35 million amortized during 1999.
(Page 8)
Total generation expenses were $1,191,000 in 1999, a decrease of $942,000 and $1,023,000 from
1998 and 1997, respectively, because of the sale of the Company's generating assets on June 8, 1999.
After the asset sale, the energy was purchased from the present owner, WPS-PDI, under a buy-back
agreement, as discussed above. Transmission and distribution expenses were $3,008,000 in 1999,
a decrease of $606,000 and $601,000 from 1998 and 1997, respectively, due to a decrease in
wheeling expenses of $883,000, principally the termination of a wheeling agreement with NB Power,
partially offset by a $302,000 increase in tree trimming expenses. Customer accounting, and general
and administrative expenses were $7,276,000, which were comparable to 1998 and an increase of
$329,000 over 1997. EA's operating and maintenance expenses were $1,037,000 for 1999, the first
year of operation, consisting of salaries, advertising, consulting and start-up expenses.
Interest expenses for 1999 were $4,236,000, compared to $4,327,000 for 1998, which had
increased by $744,000 from 1997 because of additional short-term borrowings required for Maine
Yankee replacement power costs, as well as interest recognized on the open access transmission
refund and FAME financing costs. For 1999, short-term interest expenses were reduced with the use
of asset sale proceeds to pay down the revolver, but were offset by $519,000 of carrying charges
recognized on the available value of the asset sale. Interest earned on asset sale proceeds held in
short-term investments accounted for the $759,000 increase in Interest and Dividend Income in 1999
compared to 1998.
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).
During 1998 and early 1999 the active interveners, including among others the MPUC Staff,
the Office of the Public Advocate (OPA), the Company and other owners, the Secondary
Purchasers, and a Maine environmental group (the "Settling Parties"), engaged in extensive
discovery and negotiations which resulted in the filing of a settlement agreement with the FERC
on January 19, 1999. A separate negotiated settlement filed with the FERC on February 5, 1999
resolved 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. Both settlements were found to be in the public interest and approved by
the FERC on June 1, 1999. The settlements constitute a full settlement of all issues raised in the
FERC proceeding including decommissioning-cost issues and issues pertaining to the prudence of
management, operation and decision to permanently cease operation of the Plant.
The primary settlement provided for Maine Yankee to collect $33.1 million in the aggregate
annually, effective August 1, 1999, including both decommissioning costs and costs related to
Maine Yankee's planned independent spent fuel storage installation (ISFSI). The 1997 FERC
filing had called for an aggregate annual collection rate of $36.4 million for decommissioning
and the ISFSI, based on a 1997 estimate. Pursuant to the approved settlement the amount
collected annually has been reduced to approximately $25.6 million, effective October 1, 1999,
as a result of 1999 Maine legislation allowing Maine Yankee to (1) use for decommissioning the
ISFSI funds held in trust under Maine law for spent-fuel disposal, and (2) access approximately
$6.8 million 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.
The 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 maximum allowed equity amounts, which resulted in a pro-rata refund of $9.3
million (including tax impacts) to the sponsors on July 15, 1999. The Settling Parties also
agreed 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.
Under the Maine Agreement, the Company continued 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 settlement, no refunds would be required, but such excess amounts would be
credited to the customers to the extent required by the RSP.
(Page 9)
Finally, 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 the maximum amount would be $4.1 million for the period.
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.
Beginning in May, 1998, Maine Yankee replacement power costs have been offset by net savings
from the restructured Purchase Power Agreement with Wheelabrator-Sherman, in accordance with
the rate plan stipulation. Beginning in April, 1999 the Company began amortizing an additional
$150,000 per month as part of a stipulation described in the "Regulatory Proceedings - Four-Year Rate Stabilization Plan" section of this Annual Report. As of December 31, 1999, the
Company has a deferred Maine Yankee replacement power cost balance of approximately $3.0
million, subject to recovery in accordance with the rate plan.
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 and again in June, 1999, 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 regulation 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, 1999, is carrying on its consolidated balance sheet a regulatory asset and
a corresponding liability in the amount of $32.2 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. As discussed in the "Regulatory Proceedings-MPUC Approves Elements of Rates
Effective March 1, 2000" section of this Annual Report, the MPUC on January 27, 2000,
approved a Stipulation providing for the recovery of stranded investment, which includes the
Company's share of Maine Yankee decommissioning expenses, Maine Yankee replacement power
costs, and the remaining Maine Yankee investment.
Earnings and Dividends
For 1999, the earnings per share were $2.48 based on net income available for Common
Stock of $4,005,556. 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. The average shares outstanding for all three years were 1,617,250.
Earnings for the three-year period were impacted by the closing of Maine Yankee. As
discussed in the "Maine Yankee" section of this Annual Report, the plant did not operate after
December 1996 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 and 1999 improved by $2.66 and
$.24 per share, respectively, when Maine Yankee began the process of decommissioning and
costs were reduced.
The Company's return on equity for 1999 was 11.1% compared to 6.51% for 1998 and a
negative 6.02% for 1997. Although the $19.9 million gain on the sale of the Company's
generating assets was deferred as of December 31, 1999, the Company did recognize $389,000 of
net income reflecting excess deferred income taxes and unamortized investment tax credits on the
generating assets sold. The gain will begin to be amortized in 2000, significantly reducing
stranded costs revenue requirements as approved by the Maine Public Utilities Commission as
part of the rate order period beginning March 1, 2000.
The dividends paid in 1999 were $1.05 per share after your Board increased the quarterly
dividend from $.25 to $.30 per share effective for the October 1, 1999 payment. Your Board of
Directors had reduced the quarterly dividend from $.46 to $.25 per share starting with the April
1, 1997 payment. This 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.
The dividends paid in 1998 and 1997 were $1.00 and $1.21 per share, respectively. 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 June 8, 1999 sale of the generating assets had a significantly favorable impact on the
financial strength of the Company. The proceeds of $37.5 million have been used or earmarked
for related tax and transition payments, as well as long- and short-term debt redemptions. Net
cash flows provided by operating activities for 1999 were $5.3 million. A total of $18.0 million
of the proceeds was deposited with the First Mortgage Trustee, subsequently a $4.0 million
drawdown was used for the final redemption of $2.5 million of the 9.6% series of second
mortgage bonds and a redemption of $1.4 million of the 1996 variable interest Public Utility
Refunding Revenue Bonds. In addition to the redemptions mentioned above, $1.3 million of
scheduled principal payments were made, for a total of $5.2 million in long-term debt
retirements. During 1999, the Company paid $1.3 million in dividends and spent $4.8 million for
electric plant. The Company also withdrew the final $.4 million from the proceeds held in trust
from the 1996 tax-exempt bond issuance and decreased short-term borrowings by $4.5 million
with a portion of the asset sale proceeds.
(Page 10)
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 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 had 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.
For additional information regarding construction expenditures for 1997 to 1999 and
anticipated construction expenditures for 2000, see Note 11, "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 1999, the Company had $3.6 million of short-term
debt compared to $8.1 million and $7.2 million at the end of 1998 and 1997, respectively.
During 1997 to 1999, 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 6, "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
As discussed in the "Regulatory Proceedings - Industry Restructuring" and "Regulatory
Proceeding - MPUC Approves Elements of Rates Effective March 1, 2000" sections of this
Annual Report, the sale of the Company's generating assets will significantly impact the
Company's capital structure. The deferred gain of $19.9 million from the sale will be used to
reduce stranded costs revenue requirements beginning March 1, 2000. However, the after-tax
proceeds from the sale and the liquidation of the Canadian subsidiary were used to reduce long-term debt by $3.9 million in 1999 and an additional $18.5 million will be used to reduce debt in
2000, which will in turn reduce future interest costs.
After several years of negotiations, the Company 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 amended PPA has helped 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 interest 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 1999, the
cumulative effective interest rate, including issuance costs and credit enhancement fees, since
issuance for this series was 6.37%.
(Page 11)
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 second mortgage bonds of $18.8
million without bondable property additions.
With the generating asset sale and the rate orders effective March 1, 2000, the Company will
be required to maintain a capital structure with 51% common equity, in accordance with a
Stipulation approved by the MPUC on December 1, 1999 in the Company's rate design and
stranded cost recovery cases. In anticipation of this requirement, the Company sought approval,
which the MPUC granted on November 17, 1999, to repurchase up to 500,000 shares of its
common stock over a five-year period through an open market program, which began in February,
2000.
In order to maintain the Company's common equity at levels appropriate for an investor-owned utility, the Company had already 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.
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 adjusted the interest coverage tests for the
first three quarters of 1998. With these amendments, the Company achieved its amended interest
coverage tests for the first three quarters of 1998. Starting with the fourth quarter of 1998, the
interest coverage tests, as prescribed in the underlying documents without amendment, have been
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.
Subsequently, the Company reduced its revolving credit line to $6 million. In addition, the
revolving credit agreement and letter of credit supporting the tax-exempt bonds due 2021 were
extended to May and June, 2000, respectively.
Employees
At the end of 1999, the Parent Company had 142 full-time employees compared to 155 for
1998. The decrease is due to the generating asset sale on June 8, 1999. The Parent's subsidiary,
Maine and New Brunswick Electrical Power Company, Ltd., (Maine and New Brunswick) has had
no employees since the generating assets sale, but had 9 full-time employees for 1998. Energy
Atlantic, the Parent's unregulated marketing subsidiary, had 10 full-time employees for 1999, its
first year of operation. Consolidated payroll costs were $6.8 million for 1999 and $6.6 million
for 1998.
Local 1837 of the International Brotherhood of Electrical Workers ratified a three-year
contract with the Parent Company, effective on October 1, 1999. The agreement included a
3.34% wage increase in the first year and a 3.5% increase in each of the last two years of the new
contract.
Maine and New Brunswick and Local 1733 of the International Brotherhood of Electrical
Workers ratified a one-year contract extension effective January 1, 1999 which included a wage
increase of 2.75%. A one-year extension for calendar year 1998 included a 1.93% wage increase.
Regulatory Proceedings
Industry Restructuring
On May 29, 1997, legislation titled "An Act to Restructure the State's Electric
Industry" was
signed into law by the Governor of Maine. The principal provisions with accounting impact on
the Company are as follows:
1. Beginning on March 1, 2000, all consumers of electricity have the right to purchase
generation services directly from competitive electricity suppliers who will not be
subject to rate regulation.
2. By March 1, 2000, the Company, Central Maine Power Company (CMP), and Bangor
Hydro-Electric Company (BHE) must divest themselves of all generation related assets
and business functions except for:
a) contracts with qualifying facilities, such as the Company's power contract with
Wheelabrator-Sherman (W-S), and conservation providers;
b) nuclear assets, namely, the Company's investment in the Maine Yankee Atomic
Power Company;
c) facilities located outside the United States, i.e., the Company's hydro facility in
New Brunswick, Canada; and
d) assets that the MPUC determines necessary for the operation of the transmission and
distribution services. 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 sale of its generating assets, see
"Generating Asset Sale" section in this Annual Report.
(Page 12)
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.
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.
According to EITF 97-4, entities should cease to apply Statement of Financial Accounting
Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulations" when
a deregulation plan is in place and the terms are known. With respect to the generation portion
of the Company's business, this occurred in the fourth quarter of 1999, when the terms where
substantially agreed upon by stipulation in the MPUC's proceeding on revenue requirements, rate
design and stranded costs in Docket 98-577. This stipulation was approved by the MPUC on
January 27, 2000. Correspondingly, the Company adopted SFAS 101 "Regulated Enterprises -
Accounting for the Discontinuation of Application of FASB Statement No. 71" for the
generation segment of its business in December 1999. SFAS 101 requires a determination of
impairment of plant assets under SFAS 121 "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" and the elimination of all effects of rate
regulation that have been recognized as assets and liabilities under SFAS 71. The Company has
determined no such impairment exists.
The Company believes that its electric transmission and distribution operations continue to
meet the requirements of SFAS 71 and that regulatory assets associated with those operations as
well as any generation-related costs that the MPUC has determined to be recoverable from
ratepayers also meet the criteria. At December 31, 1999, $86.6 million of regulatory assets
remain on the Company's books. These assets will be amortized over various periods in
accordance with the MPUC approved Phase II filing.
For further discussion of the specific impacts of the industry restructuring on the Company
and related ratemaking activity, see "MPUC Approves Elements of Rates Effective March 1,
2000" below.
MPUC Approves Elements of Rates Effective
March 1, 2000
On October 14, 1998, and subsequently amended on February 9, 1999, August 11, 1999, and
December 15, 1999, the Company filed its determination of stranded costs, transmission and
distribution costs and rate design with the MPUC. The Company's amended testimony supported
its $95.7 million estimate of stranded costs, net of available value from the sale of the generating
assets, 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.
On October 15, 1999, the Company filed with the MPUC a Stipulation resolving the revenue
requirement and rate design issues for the Company's Transmission and Distribution (T&D)
utility. This Stipulation had been signed by the Public Advocate and approval was recommended
by the MPUC Staff. Under the Stipulation, the Company's total annual T&D revenue
requirement will be $16,640,000, effective March 1, 2000. This revenue requirement includes a
10.7% return on equity with a capital structure based on 51% common equity. The Stipulation
further provided that the precise level of stranded cost recovery could not be determined until
final determination of all costs associated with the sale of the Company's generating assets, but
did set forth some general principles concerning the Company's ultimate stranded costs recovery,
including agreement that the major components of the Company's stranded costs are legitimate,
verifiable and unmitigable, and therefore subject to recovery in rates. Furthermore, the
Stipulation allowed the 3.66% foregone revenue increase as a result of a rate plan Stipulation
approved by the MPUC in its April 6, 1999 Order in Docket 98-865 to be recovered through a
reduction in the deferred gain on the asset sale. The Stipulation also provided that the
Company's recovery of unamortized investment tax credits and excess deferred income taxes
associated with the Company's generating assets must await a final determination ruling from the
IRS, which ruling was sought by Central Maine Power Company (CMP). On December 1, 1999,
the MPUC approved the October 15, 1999 Stipulation, as described above. In early January,
2000, CMP received its ruling from the IRS which concluded that the unamortized investment tax
credits and excess deferred income taxes associated with the sale of the generating assets could
not be used to reduce customer rates without violating the tax normalization rules for Public
utilities. Therefore, the Company has recognized these excess deferred taxes in income, which
amounted to an increase in net income of approximately $389,000 or $.24 per share.
(Page 13)
On January 27, 2000, the MPUC approved a Stipulation in Phase II of Docket No. 98-577
that provided for the recovery in rates of the Company's stranded investment. The major
element of the Phase II Stipulation was the $12.5 million of stranded investment recoverable
annually beginning March 1, 2000. This revenue requirement includes a return on unrecovered
stranded investment based on the capital structure approved by the MPUC in its December 1,
1999 Order. The approved capital structure will consist of 51% common equity with an
authorized return on equity of 10.7%. The Phase II Stipulation also allowed the Company to
offset its unrecovered stranded investment in Seabrook by approximately $7 million,
representing an amount equal to 35% of the available value from the sale of the generation assets.
The parties to the Phase II Stipulation also resolved several rate design issues, principally the
elimination of the inclining block rate for residential customers. In addition, the Company was
granted several accounting orders incorporating certain accounting methodologies used in
determining the elements of stranded costs. The annual revenue requirement associated with the
recovery of stranded costs will be reviewed every two years.
With the award of the standard offer rate on November 18, 1999, and orders approving the
Company's T&D rates and stranded investment recovery rates described above, the MPUC has
established all elements of customer rates effective March 1, 2000, the beginning of deregulation
in Maine. On average, our customers' rates will be reduced by approximately 6%.
After paying off debt with proceeds from the sale of the Company's generating assets, as
required under the Company's mortgage indentures, the Company projects that the percentage of
common equity as a component in its capital structure would exceed 51%. In order to manage its
capital structure to limit common equity to 51%, the MPUC, on November 17, 1999, approved
the Company's request to repurchase up to 500,000 shares of its common stock over a period of
five years. The shares will be repurchased through an open-market program.
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 was required by the State's electric industry
restructuring law. The gain from the asset sale will reduce stranded cost revenue requirements,
as discussed in the "MPUC Approves Elements of Rates Effective March 1, 2000" section of this
Annual Report.
The Company consummated the sale to WPS-PDI on June 8, 1999 after receiving all of the
major regulatory approvals. The Company's 5% ownership in Maine Yankee was not part of the
sale, since the plant is being decommissioned. After paying Canadian, Federal and State income
taxes, the remaining proceeds, along with interest in the trust account, will be used to reduce the
Company's debt by $22.4 million. The gain from the sale has been deferred, as required by the
MPUC. The components of the deferred gain are as follows:
(Dollars in Millions)
Gross proceeds $ 37.5
Settlement adjustments (.1)
Net proceeds 37.4
Net book value (11.5)
Excess taxes on sale of
Canadian Assets (3.4)
Transition costs, net (1.8)
Deferred RSP rate increase (1.3)
Other .5
Deferred gain * $ 19.9
* The $19.9 million deferred gain above is the $20.2 million "Deferred Gain and
Related Accounts" as of December 31, 1999 reduced by the remaining deferral of
transition costs allowed by the MPUC.
Upon liquidation of the subsidiary in December 1999, $14.1 million of the proceeds was
transferred to the first mortgage trustee for eventual paydown of long-term debt.
After the sale of the Company's generating assets in June, 1999, the Company purchased
energy from the new owners, under an agreement that expires February 29, 2000.
As part of the generating asset sale, the Company has entered into two indemnity obligations
with the purchaser, WPS-PDI. First, the Company will be liable, with certain limitations, for
certain Aroostook River flowage damage. This liability will continue for ten years after the sale
and shall not exceed $2,000,000 in the aggregate. Second, the Company has warranteed the
condition of the sites sold to WPS-PDI, with an aggregate limit of $3,000,000 for two years after
the date of sale, and five years after the sale for environmental claims. The Company is unaware
of any pending claims under either of these indemnity obligations.
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 provided our customers with predictable rates until March 1, 2000, and shares
operating risks and benefits between the Company's shareholders and customers. As described in
the "Industry Restructuring" and "MPUC Approves Elements of Rates Effective March 1, 2000"
sections of this Annual Report, March 1, 2000 is the beginning of industry restructuring and new
rates.
(Page 14)
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 agreed that it would
seek no other increases, for either base or fuel rates, except as provided under the terms of the
plan. There were 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 permitted
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 provided 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.
For the final year of the rate plan beginning February 1, 1999, the Company filed on
November 13, 1998, 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. On December 15, 1998, the MPUC granted the Company's request to defer the increase
to April 1, 1999, as well as extend the rate plan by one month to February 29, 2000, to coincide
with the start of retail competition in Maine.
In its April 6, 1999 Order, the MPUC approved a March 25, 1999 Stipulation between the
Office of the Public Advocate (OPA) and the Company. Under this Stipulation, customer rates
would not increase on April 1, 1999, if the MPUC approved the sale of the Company's generation
assets. The approval of the Stipulation also resolved certain issues associated with the treatment
of capacity cost savings from the closure of Maine Yankee under the Company's rate
stabilization plan.
The principal provisions are as follows:
1. The Company is entitled to a 3.66% specified rate increase as of April 1, 1999. Rather
than increase customer rates, the Company will recognize the revenues that this increase
would have generated and, correspondingly, record a deferred asset on the Company's
books of account. The parties to the Stipulation also agreed to recommend the use in
rates of available value from the asset sale corresponding with the specified rate increase
once the MPUC determines the Company's allowed stranded cost recovery in Docket No.
98-577, Public Utilities Commission, Investigation of Stranded Costs, Transmission and
Distribution Utility, Revenue Requirements and Rate Design of Maine Public Service
Company.
2. The Stipulation also resolves a dispute over the determination of Maine Yankee
replacement power costs. The Stipulation allows the Company to continue to recognize
and defer Maine Yankee replacement power costs on an energy-only basis, offset by
Wheelabrator-Sherman contract restructuring savings, through the end of the rate plan.
The Company agreed to begin amortizing on April 1, 1999, Maine Yankee replacement
power costs in the amount of $150,000 per month or a total of $1,650,000 for the
remaining eleven months of the rate plan.
3. With the Commission's approval of the generation asset sale, the parties agreed that the
Company would not increase retail rates on April 1, 1999, to reflect any increase under
the Maine Yankee replacement power provision of the rate plan. Any Maine Yankee
deferred replacement costs will be deferred, and, beginning on March 1, 2000, will be
offset by a corresponding amount of available value as allowed in Docket No. 98-577.
As described in the "MPUC Approves Elements of Rates Effective March 1, 2000" section of this
Annual Report, the MPUC approved a Stipulation providing for the recovery in rates of stranded
investment, which includes the deferrals allowed under the rate plan.
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 amended PPA has helped 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.
The Company estimates its remaining commitment to purchase power under this contract to
be $84.2 million from March 1, 2000 through 2006. The Company has entered a contract
whereby WPS-PDI takes delivery of the power through February 28, 2002 at market prices. The
Company estimates that the remaining stranded costs will be $58.7 million through 2006,
assuming arrangements similar to the one with WPS-PDI will be in place for that period.
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, as subsequently
ordered by the MPUC in Docket 98-577. See also the "MPUC Approves Elements of Rates
Effective March 1, 2000" section of this Annual Report. 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 15)
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 reflected the
$1.2 million refunds as liabilities as of December 31, 1998 and made the payments to these
customers on May 20, 1999.
Year 2000 Issues
The Company encountered no computer system or operational difficulties related to Year
2000 computer issues. The Company incurred approximately $33,000 of internal labor for
review and testing prior to December 31, 1999, which did not identify material modifications.
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, 1999 and 1998, Common Stock shares issued and outstanding were 1,617,250.
As of December 31, 1999, shares were held by 1,175 shareholders or nominees in forty-eight
states, the District of Columbia, Canada, and the United Kingdom.
The annual meeting of shareholders is held each year on the second Tuesday in May at
the Company's headquarters in Presque Isle. Market price and dividend information relative to
the two most recent calendar years are shown in the tabulation on the following page.
Income Tax Status of 1999 Dividends
The Company has determined that the Common Stock dividends paid in 1999 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.
(Page 16)
Market Dividends Dividends
Price Paid Declared
High Low Per Share Per Share
1999
First Quarter $16-1/8 $13-1/8 $ .25 $ .25
Second Quarter $17-7/8 $12-7/8 .25 .25
Third Quarter $19-1/8 $17-7/16 .25 .30
Fourth Quarter $19 $16-1/2 .30 .30
Total Dividends $ 1.05 $ 1.10
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
Dividends declared within the quarter are paid on the first day of the succeeding quarter.
Five-Year Summary of Selected Financial Data
1999 1998 1997 1996 1995
Operating Revenues $67,456,117 $56,626,906
$55,072,196 $57,264,165 $55,278,726
Income (Loss) Before
Extraordinary Items $4,005,556 $2,252,915 $(2,177,137) $2,110,694 $920,500
Extraordinary Items, Net of Taxes - - - - (6,235,812)
Income (Loss) Available for
Common Stock $4,005,556 $2,252,915 $(2,177,137) $2,110,694 $(5,315,312)
Basic Earnings (Loss) Per Share of Common Stock
Income (Loss) Before
Extraordinary Items $2.48 $1.39 $(1.35) $1.31 $0.57
Extraordinary Items -- -- - -- $(3.86)
Net Income (Loss) $2.48 $1.39 $(1.35) $1.31 $(3.29)
Dividends Per Share of Common Stock:
Declared Basis $1.10 $1.00 $1.00 $1.84 $1.84
Paid Basis $1.05 $1.00 $1.21 $1.84 $1.84
Total Assets $171,548,480 $164,295,548 $163,480,739 $117,192,566 $114,074,091
Long-Term Debt Outstanding $42,015,000 $47,190,000 $39,805,000 $41,120,000 $37,435,000
Less amount due within one year $25,000 $1,275,000 $4,155,000 $1,315,000 $1,315,000
Long-Term Debt $41,990,000 $45,915,000 $35,650,000 $39,805,000 $36,120,000
(Page 17)
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 Subsidiaries as of December 31, 1999 and 1998, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1999, in conformity with accounting
principles generally accepted in the United States. 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 auditing standards generally accepted in the United
States 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 10, 2000
(Page 18)
MAINE PUBLIC SERVICE COMPANY AND
SUBSIDIARIES
Statements of Consolidated Operations
Year Ended December 31,
1999 1998 1997
Operating Revenues $67,456,117 $56,626,906 $55,072,196
Operating Expenses
Purchased Power 39,072,521 29,517,841 36,608,989
Other Operation and Maintenance 12,512,124 12,967,489 12,769,987
Depreciation 2,346,285 2,641,847 2,497,364
Amortization 1,479,098 1,607,262 1,641,819
Taxes Other Than Income 1,439,870 1,609,001 1,618,208
Provision (Benefit) for Income Taxes 3,529,542 2,118,095 (975,093)
Total Operating Expenses 60,379,440 50,461,535 54,161,274
Operating Income 7,076,677 6,165,371 910,922
Other Income (Deductions)
Equity in Income of Associated Companies 491,024 316,888 477,426
Interest and Dividend Income 902,146 142,840 204,532
Allowance for Equity Funds Used During
Construction 51,248 36,278 18,964
Provision for Income Taxes 130,592 (49,847) (61,183)
Other - Net (410,034) (31,325) (144,666)
Total 1,164,976 414,834 495,073
Income Before Interest Charges 8,241,653 6,580,205 1,405,995
Interest Charges
Long-Term Debt and Notes Payable 4,268,315 4,347,258 3,592,474
Less Allowance for Borrowed Funds
Used During Construction (32,218) (19,968) (9,342)
Total 4,236,097 4,327,290 3,583,132
Net Income (Loss) Available for
Common Stock $4,005,556 $2,252,915 $(2,177,137)
Basic Earnings (Loss) Per Share
of Common Stock $2.48 $1.39 $(1.35)
Average Shares Outstanding 1,617,250 1,617,250 1,617,250
See Notes to Consolidated Financial Statements.
(Page 19)
MAINE PUBLIC SERVICE COMPANY AND
SUBSIDIARIES
Statements of Consolidated Cash Flows
Year Ended December 31,
1999 1998 1997
Cash Flow From Operating Activities
Net Income (Loss) $4,005,556 $2,252,915 $(2,177,137)
Adjustments to Reconcile Net Income (Loss) to
Net Cash Provided by (Used For) Operations:
Depreciation 2,346,285 2,641,847 2,497,364
Amortization 1,398,256 1,643,842 1,677,399
Deferred Income Taxes - Net 2,225,933 1,698,938 812,897
Deferred Investment Tax Credits and
Excess Deferred Income Taxes (438,270) (70,200) (72,267)
Allowance for Funds Used During
Construction (83,466) (56,246) (28,306)
Income on Tax-Exempt Bonds-
Restricted Funds (8,830) (90,700) (159,114)
Change in Deferred Regulatory and
Debt Issuance Costs (2,003,759) (1,840,141) (2,304,765)
Wheelabrator-Sherman Contract Restructuring -- (8,705,750) --
Gain on Sale of Miscellaneous Property (14,935) -- --
Change in Deferred Revenues (1,170,136) 267,921 272,716
Change in Benefit Obligations (1,371,238) 344,121 546,080
Change in Current Assets and Liabilities:
Accounts Receivable and
Unbilled Revenue (495,353) (274,525) (800,549)
Deferred Fuel and Purchased
Energy Cost (300,000) -- (562,000)
Other Current Assets 92,371 1,862,179 (1,266,582)
Accounts Payable 1,079,246 (1,200,161) 396,259
Accrued Taxes and Interest 952,454 148,897 (82,632)
Other Current Liabilities (7,375) (18,150) (19,530)
Other - Net (912,023) (752,067) (448,950)
Net Cash Flow Provided By (Used For)
Operating Activities 5,294,716 (2,147,280) (1,719,117)
Cash Flow From Financing Activities
Dividend Payments (1,293,800) (2,021,562) (1,212,938)
Bond Issuance Costs (102,705) (543,904) --
Deposit of Asset Sale Proceeds with
Trustee, net (17,998,000) -- --
Deposit - FAME Capital Reserve Fund -- (2,378,386) --
Issuance of Long-Term Debt -- 11,540,000 --
Drawdown of Tax-Exempt Bond Proceeds 427,886 1,934,540 1,950,692
Retirements of Long-Term Debt (5,175,000) (4,155,000) (1,315,000)
Short-Term Borrowings, Net (4,500,000) 900,000 5,800,000
Net Cash Flow Provided By Financing Activities (28,641,619) 5,275,688 5,222,754
Cash Flow Used In Investing Activities
Proceeds from Sale of Generating Assets 37,547,381 -- --
Prepayment of Taxes on Generating Asset Sale
Deferred Gain (3,925,049) -- --
Proceeds from Sale of Miscellaneous Property 19,800 -- --
Investment in Electric Plant (4,763,782) (3,745,302) (2,723,828)
Net Cash Flow Used In Investing Activities 28,878,350 (3,745,302) (2,723,828)
Increase (Decrease) in Cash and Cash Equivalents 5,531,447 (616,894) 779,809
Cash and Cash Equivalents at Beginning of Year 1,453,826 2,070,720 1,290,911
Cash and Cash Equivalents at End of Year $6,985,273 $1,453,826 $2,070,720
Supplemental Disclosure of Cash Flow Information:
Cash Paid During The Year For:
Interest $4,289,102 $3,763,628 $ 3,360,855
Income Taxes (1999, 1998 and 1997 are
net of tax refunds of $208,836,
$2,083,783 and $851,506, respectively) $5,273,330 $(1,238,467) $ (370,709)
See Notes to Consolidated Financial Statements.
(Page 20)
MAINE PUBLIC SERVICE COMPANY AND
SUBSIDIARIES
Consolidated Balance Sheets
Assets
December 31,
1999 1998
Utility Plant
Electric Plant in Service $ 75,530,269 $101,210,738
Less Accumulated Depreciation 34,700,921 51,584,662
Net Electric Plant in Service 40,829,348 49,626,076
Construction Work-In-Progress 1,052,273 1,014,402
Total 41,881,621 50,640,478
Investments in Associated Companies 4,032,181 4,219,693
Net Utility Plant and Investments in Associated Companies 45,913,802 54,860,171
Current Assets:
Cash and Cash Equivalents 6,985,273 1,453,826
Deposits for Interest and Dividends -- 477,193
Deposit with Trustee - Asset Sale 18,241,664 --
Accounts Receivable (less allowance for uncollectible
accounts of $215,000 in 1999 and 1998) 7,043,704 5,856,395
Unbilled Revenue 1,149,120 1,892,320
Deferred Fuel and Purchased Energy Costs 987,000 687,000
Current Deferred Income Taxes -- 30,508
Inventory 508,624 1,036,578
Income Tax Refund Receivable 150,615 191,516
Prepayments 492,498 329,834
Total 35,558,498 11,955,170
Regulatory Assets:
Uncollected Maine Yankee Decommissioning Costs 32,157,673 36,037,446
Recoverable Seabrook Costs (less accumulated amortization
and write-off in 1999, $29,735,499; 1998, $28,311,867) 23,451,511 24,875,143
Regulatory Assets-SFAS 109 & 106 10,458,698 11,886,458
Deferred Fuel and Purchased Energy Costs 10,229,762 9,617,677
Regulatory Asset - Power Purchase Agreement Restructuring 8,705,750 8,705,750
Unamortized Debt Expense (less accumulated amortization
in 1998, $880,497; in 1998, $973,404) 1,013,905 1,087,636
Deferred Regulatory Costs, less accumulated amortization 581,314 626,990
Total 86,598,613 92,837,100
Other Assets:
Restricted Investments (at cost, which approximates market) 2,401,792 2,817,254
Miscellaneous 1,075,775 1,825,853
Total 3,477,567 4,643,107
Total Assets $171,548,480 $164,295,548
See Notes to Consolidated Financial Statements.
(Page 21)
Capitalization and Liabilities
December 31,
1999 1998
Capitalization (see accompanying statements):
Common Shareholders' Equity $ 37,159,608 $ 34,933,027
Long-Term Debt 41,990,000 45,915,000
Total 79,149,608 80,848,027
Current Liabilities:
Long-Term Debt Due Within One Year 25,000 1,275,000
Notes Payable to Banks 3,600,000 8,100,000
Accounts Payable 4,777,134 3,329,730
Accounts Payable - Associated Companies 263,196 341,210
Accrued Employee Benefits 676,837 1,000,130
Deferred Income Taxes Related to Deferred Fuel Costs 194,911 --
Dividends Declared 485,176 404,313
Customer Deposits 17,092 24,467
Taxes Accrued 9,131,138 57,437
Interest Accrued 656,346 971,271
Total 19,826,830 15,503,558
Deferred Credits:
Deferred Revenues -- 1,170,136
Uncollected Maine Yankee Decommissioning Costs 32,157,673 36,037,446
Income Taxes 17,160,240 25,812,477
Investment Tax Credits 287,713 578,006
Deferred Gain & Related Accounts-Generating Asset sale 20,227,199 --
Miscellaneous 2,739,217 4,345,898
Total 72,572,042 67,943,963
Commitments, Contingencies, and Regulatory Matters (Note 11)
Total Capitalization and Liabilities $171,548,480 $164,295,548
(Page 22)
MAINE PUBLIC SERVICE COMPANY AND
SUBSIDIARIES
Statements of Consolidated Income
Statement of Consolidated Common Shareholders' Equity
Par Value Paid-In Retained Treasury
Shares Issued Capital Earnings Stock
Balance, January 1, 1997 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)
Net Income 4,005,556
Dividends:
Common Stock ($1.10 per share) (1,778,975)
Balance, December 31, 1999 1,617,250 $ 13,070,750 $ 38,317 $ 29,764,917 $ (5,714,376)
See Notes to Consolidated Financial Statements.
(Page 23)
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
1999 1998
Common Shareholders' Equity
Common Stock, $7 Par Value-Authorized 3,000,000 Shares in
1999 and 1998; Issued 1,867,250 Shares in 1999 and 1998 $13,070,750 $13,070,750
Paid-In-Capital 38,317 38,317
Retained Earnings 29,764,917 27,538,336
Total 42,873,984 40,647,403
Treasury Stock-Total Shares of 250,000 in 1999 and 1998, at cost (5,714,376) (5,714,376)
Total $37,159,608 $34,933,027
Long-Term Debt
First Mortgage and Collateral Trust Bonds:
7.95% Due Serially through 2003-Interest Payable,
March 1 and September 1 * $ 1,875,000 $ 1,900,000
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
Public Utility Refunding Revenue Bonds:
Series 1996: Due 2021-Variable Interest Payable Monthly
(5.55% as of December 31, 1999) 13,600,000 15,000,000
Finance Authority of Maine:
1998 Taxable Electric Rate Stabilization
Revenue Notes: Due 2008 - Variable Interest Payable Monthly
(6.45% as of December 31, 1999) 11,540,000 11,540,000
Total Outstanding 42,015,000 47,190,000
Less-Amount Due Within One Year 25,000 1,275,000
Total $41,990,000 $45,915,000
Current Maturities and Redemption Requirements for the Succeeding Five Years Are as Follows:
Long-Term Debt:
2000 $ 25,000
2001 $ 2,410,000
2002 $ 2,535,000
2003 $ 4,445,000
2004 $ 2,810,000
Thereafter $29,790,000
* Subject to early redemption premiums as defined in the bond indentures.
See Notes to Consolidated Financial Statements.
(Page 24)
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,
its wholly-owned Canadian subsidiary, Maine and New Brunswick Electrical Power Company,
Limited (Maine and New Brunswick), and its wholly-owned marketing subsidiary, Energy
Atlantic, LLC (EA). All intercompany balances and transactions have been eliminated in
consolidation.
The preparation of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Foreign Currency Translation
The functional currency of Maine and New Brunswick is the U.S. dollar. Accordingly,
translation gains and losses are included in other income. Income and expenses of Maine and
New Brunswick 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. In October 1999, in
preparation for retail competition, the Company converted all residential customers to monthly
meter reading while the majority had been previously read bi-monthly.
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 issued a refund of approximately $1.2 million in 1999.
On April 1, 1999, the Company began recognizing revenue from the foregone 3.66% rate
increase, with an offset to the available value from the sale of the generating assets in accordance
with the rate stipulations approved by the MPUC. During 1999, $1.3 million of revenue was
recognized under this Stipulation, as discussed further in Note 11, "Commitments,
Contingencies, and Regulatory Matters".
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 2.74%, 2.99%, and 3.01% for 1999, 1998, and 1997, 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 11).
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 4) using the equity
method.
Pledged Assets
The Common Stock of Maine and New Brunswick is pledged as additional collateral for the
First and Second Mortgage and collateral trust bonds of the Company. In December, 1999, a
liquidating dividend in the amount of $14.8 million, representing after-tax proceeds from the sale
of the generating assets was paid by Maine and New Brunswick to the Company. In accordance
with the mortgage indentures, the dividend net of withholding taxes was deposited with the first
mortgage trustee.
(Page 25)
Inventory
Inventory is stated at average cost.
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 1999, the Company adopted SFAS No. 101, "Regulated Enterprises - Accounting for
the Discontinuation of Application of FASB Statement No. 71" for its generation operations with
no material impact to the Company's financial position, or results of operations. The Company
also adopted EITF 98-10 "Accounting for Companies Involved in Energy Trading and Risk
Management Activities", in relation to the accounting for the Company's energy-related contracts
with no material impact to the Company's financial position or results of operations. In June
1998, the FASB issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities". 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)". Current income taxes recorded on the Company's and Subsidiary's deferred gain
from the generating asset sale are offset by corresponding deferred income taxes.
1999 1998 1997
Current income taxes $ 13,305,318 $ 539,204 $(1,654,540)
Deferred income taxes (9,857,507) 1,698,938 812,897
Investment credits, net (48,861) (70,200) (72,267)
Total income taxes $ 3,398,950 $ 2,167,942 $ (913,910)
Allocated to:
Operating income $ 3,529,542 $ 2,118,095 $ (975,093)
Other income (130,592) 49,847 61,183
Total $ 3,398,950 $ 2,167,942 $ (913,910)
The effective income tax rates differ from the U.S. statutory rate as follows:
1999 1998 1997
Statutory rate 34.0% 34.0% (34.0)%
Excess Canadian taxes .7 2.7 3.3
Amortization of recoverable Seabrook costs 3.8 6.4 9.1
State income taxes 10.1 5.9 (5.9)
Other (2.7) -- (2.1)
Effective rate 45.9% 49.0% (29.6)%
The elements of deferred income tax expense (credit) are as follows:
(Dollars in Thousands)
1999 1998 1997
Temporary Differences at Statutory Rates:
Seabrook - costs $ (200) $ (200) $ (200)
Liberalized depreciation 46 57 80
AFUDC-borrowed funds (38) (38) (38)
Deferred fuel 455 987 1,479
Deferred regulatory expense (113) (124) (266)
Unbilled and deferred revenue -- 360 (108)
Accrued pension and postretirement benefits 723 (112) (182)
Wheelabrator-Sherman power purchase
restructuring 1,344 784 --
Generating Asset Sale (11,956) -- --
Other (119) (15) 48
Total temporary differences - statutory rates $ (9,858) $ 1,699 $ 813
(Page 26)
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
$16,281,664 and $678,426 in 1999 and 1998, respectively, while no dividend was received in
1997. In addition to $1,481,644 of regular dividends in 1999, the Subsidiary paid a liquidating
dividend of $14,800,000. The regular dividends exceeded earnings by $932,304 and $311,335 in
1999 and 1998, respectively.
The following summarizes accumulated deferred income taxes established on temporary
differences under SFAS 109 as of December 31, 1999 and 1998.
(Dollars in Thousands)
1999 1998
Seabrook $12,922 $13,706
Property 6,249 8,532
Regulatory expenses 2,476 2,002
Deferred fuel 1,688 2,056
Generating asset sale (7,666) --
Wheelabrator-Sherman
Upfront Payment 2,129 --
Pension and post-
retirement benefits (206) (952)
Other (432) 468
Net accumulated deferred
income taxes $17,160 $25,812
3. ENERGY ATLANTIC
In January, 1999, Energy Atlantic, LLC (EA), the Company's wholly-owned unregulated
marketing subsidiary, formally began operations. EA was involved in wholesale energy
transactions in 1999 and will enter the retail market on March 1, 2000, the start of retail
competition in Maine. On November 29, 1999, the MPUC designated EA as the Standard Offer
Service (SOS) provider for all residential and small non-residential customers in Central Maine
Power's (CMP) Service territory for the two-year period beginning March 1, 2000. EA was also
awarded 20% of the SOS for medium non-residential customers in the Company's territory for
one year. As the SOS provider, EA is committed to supply energy to these customers, and has
entered a contract with Engage Energy (Engage), a large energy provider, to obtain the supply
required for the SOS periods. Pursuant to the terms of the contract with Engage, EA has pledged
its cash and all receivables to secure payment for the energy supplied by Engage.
As a start-up unregulated company, the Company's Board of Directors, 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 served our largest wholesale
customer, Houlton Water Company during 1999, which accounted for 51.7% of EA's gross
revenues.
During the quarter ended March 31, 1999, the Company began applying Statement of
Financial Accounting Standards (FAS) No. 131, "Disclosure about Segments of an Enterprise and
Related Information", as a result of the start-up of Energy Atlantic. Segment reporting has been
presented below for the current period only since historically there had not been separate
reportable segments. The accounting policies of the segments are the same as those described in
Note. 1, "Accounting Policies". The Company provides certain administrative support services
to Energy Atlantic, which are billed to that entity based on a combination of direct charges and
allocations. The Company is organized on the basis of products and services. The Company's
reportable segments includes the electric utility portion of the business, consisting of Maine
Public Service Company and Maine and New Brunswick Electrical Power Company, Limited
(MPS), and the energy marketing portion of the business, consisting of EA.
1999
(Dollars in Thousands)
Total
EA MPS Company
Operating Revenues $ 8,429 $ 59,027 $ 67,456
Operations & Maintenance
Expense 8,973 47,876 56,849
Taxes (209) 3,739 3,530
Total Operating Expenses 8,764 51,615 60,379
Operating Income (Loss) (335) 7,412 7,077
Other Income & Deductions 4 1,161 1,165
Income (Loss) Before (331) 8,573 8,242
Interest Charges
Interest Charges 23 4,213 4,236
Net Income (Loss) $ (354) $ 4,360 $ 4,006
Total Assets as of
December 31, 1999 $ 1,445 $170,103 $171,548
(Page 27)
4. 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 11, "Commitments, Contingencies, and
Regulatory Matters -- Capacity Arrangements" regarding the closing and decommissioning of
Maine Yankee.
Dividends received during 1999, 1998, and 1997 from Maine Yankee were approximately
$453,750, $108,750, and $75,000, respectively, and from MEPCO $207,974 in 1999 and
approximately $7,300 in 1998 and 1997. Substantially all earnings of Maine Yankee and
MEPCO are distributed to investor companies. Condensed financial information (unaudited) for
Maine Yankee and MEPCO is as follows:
(Dollars in Thousands) Maine Yankee MEPCO
1999 1998 1997 1999 1998 1997
Earnings
Operating revenues $ 69,439 $ 110,608 $ 238,586 $ 2,738 $ 3,514 $ 25,123
Earnings applicable to
Common Stock $ 4,863 $ 4,916 $ 7,613 $ 3,309 $ 948 $ 1,463
Company's equity share
of net earnings $ 243 $ 246 $ 381 $ 248 $ 71 $ 110
Investment
Total assets $1,049,972 $1,183,298 $1,368,143 $ 7,772 $ 5,581 $ 4,362
Less:
Preferred stock 15,000 16,800 17,400 -- -- --
Long-term debt 48,000 48,000 76,665 -- 220 420
Other liabilities and
deferred credits 911,994 1,039,008 1,195,128 4,043 2,146 1,578
Net assets $ 74,978 $ 79,490 $ 78,950 $ 3,729 $ 3,215 $ 2,364
Company's equity in
net assets $ 3,749 $ 3,975 $ 3,948 $ 279 $ 241 $ 177
5. INVESTMENT IN JOINTLY-OWNED UTILITY PLANT
As more fully explained in Note 11, "Commitments, Contingencies, and Regulatory Matters -
Capacity Arrangements", the Company sold its 3.3455% ownership interest in a jointly-owned utility
plant, W. F. Wyman Unit No. 4 (Wyman), an oil-fired generation plant on June 8, 1999, as required by
the Maine utility industry restructuring legislation. 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 was $6,987,000, less
accumulated depreciation of $4,654,000.
6. SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit arrangement with two banks for borrowings up to $6 million.
The revolving credit agreement is subject to extension with the consent of the participating banks and
has been extended through May 24, 2000. As part of amendments to the Company's revolving credit
agreement and line of credit agreement, it was decreased from $10 million to $6 million at the
Company's request as of October 8, 1999. These agreements contain certain restrictive covenants
including interest coverage tests and debt to equity ratios. As of December 31, 1999, 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. The B Loans bear interest as arranged
between the Company and the participating bank. As of December 31, 1999, an A Loan for $3 million
and a B Loan for $600,000 were outstanding under this arrangement at 7.5% and 6.51%, respectively.
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.
The Canadian subsidiary, Maine and New Brunswick, 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 1999.
(Page 28)
7. COMMON SHAREHOLDERS' EQUITY
On November 17, 1999, the Maine Public Utilities Commission (MPUC) authorized the repurchase
of up to 500,000 shares of the Company's Common Stock in order to maintain the Company's capital
structure at levels in accordance with the Stipulation approved by the MPUC on December 1, 1999.
The Stipulation limits common equity to 51% of the capital structure. The shares will be repurchased
through an open-market program. Previously, over a five-year period from September, 1989 to
September, 1994 under a similar program, the Company 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 $29,764,917 at December 31, 1999.
8. 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. No contribution was
necessary for the 1999 plan year. For the 1998 and 1997 plan years, the Company has made
contributions of $330,000 in 1999 and $305,000 in 1998, 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 9.8% in
1999. 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. As required by the MPUC, the Company
made a payment of $2.1 million to a Voluntary Employee Benefit Association (VEBA) trust
fund on December 28, 1999. The VEBA is 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. For purposes of determining the accrued postretirement
benefit cost as of December 31, 1999, the health care cost trend rate used was 9% in 2000
and graded down to 4.0% for 2009, remaining at that level thereafter. 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 $81 $(64)
Effect on postretirement benefit
obligation $573 $(476)
The following table sets forth the plans' change in benefit obligation, change in plan
assets, funded status and assumptions as of December 31, 1999 and 1998:
Pension Health Care
(Dollars in Thousands) Benefits Benefits
1999 1998 1999 1998
Changes in benefit obligation
Benefit obligation at
beginning of year $15,746 $14,685 $5,991 $4,933
Service cost 377 377 107 119
Interest cost 1,033 998 367 335
Special Termination
Benefits 54 -- -- --
Amendments -- -- (724) --
Curtailment gain (167) -- -- --
Actuarial (gain) loss (1,819) 585 (637) 848
Benefits paid (922) (899) (318) (244)
Benefit obligation at
end of year 14,302 15,746 4,786 5,991
Change in plan assets
Fair value of plan assets at
beginning of year 16,883 15,123 -- --
Actual return on plan assets 1,570 2,354 -- --
Employer contribution 330 305 2,419 244
Benefits paid (922) (899) (318) (244)
Fair value of plan assets
at end of year 17,861 16,883 2,101 --
Funded Status 3,559 1,137 (2,685) (5,991)
Unrecognized transition
(asset) obligation (248) (326) 2,754 2,967
Unrecognized prior service cost 626 741 (708) --
Unrecognized net actuarial
(gain)/loss (5,423) (3,170) (130) 508
Accrued benefit cost $(1,486) $(1,618) $(769) $(2,516)
Weighted-average assumptions as
of December 31 (measurement date)
Discount rate 7.75% 6.75% 7.75% 6.75%
Expected return on plan assets 8.50% 8.50% 7.50% N/A
Rate of compensation increase 4.50% 4.50% N/A N/A
(Page 29)
The following table sets forth the plans' net periodic benefit cost for 1999, 1998, and 1997:
(Dollars in Thousands) Pension Benefits Health Care Benefits
1999 1998 1997 1999 1998 1997
Service cost $377 $377 $323 $107 $119 $103
Interest cost 1,033 998 964 367 335 343
Expected return on plan assets (1,136) (1,044) (981) -- -- --
Amortization of transition obligation (77) (77) (77) 213 213 213
Amortization of prior service cost 73 76 76 (15) -- --
Curtailment (1) -- -- -- -- -- --
Recognized net actuarial (gain) -- -- -- -- -- (2)
Net periodic benefit cost $270 $330 $305 $672 $667 $657
(1) Curtailment
In 1999, the termination of employees at the U.S. generating facilities due to the generating asset sale
on June 8, 1999, qualified as a curtailment for purposes of calculating the pension benefit obligation. As a
result, the net curtailment gain reduced the accrued transition costs related to the asset sale. These benefits
have been deferred and, according to the treatment approved by the MPUC, will be amortized over four
years beginning March 1, 2000.
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 $58,000, $56,000, and $55,000, in 1999, 1998, and 1997, respectively.
Amendments to Health Care Benefits
Effective January 1, 2000, several amendments were made to the Company's health care benefits and
were considered in the calculations above. These amendments are designed to mitigate the impact on the
Company of rising medical coverage premiums and include the raising of deductibles, employee/retiree
contributions, and prescription drug co-pay amounts.
9. LONG-TERM DEBT
The sale of the Company's generating assets will significantly impact long-term debt. In 1999,
proceeds from the sale were deposited with the first mortgage trustee and subsequently withdrawn to redeem
the remaining $2.5 million 9.6% Second Mortgage Bonds and $1.4 million of the variable rate 1996 Public
Utility Refunding Revenue Bonds. It is anticipated that approximately $16 million of the proceeds will be
used to redeem other long-term debt in 2000 and $2.5 million used to reduce short-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 1999, the cumulative effective interest rate, including issuance costs and credit
enhancement fees, since issuance for this series was 6.37%.
Certain long-term debt is subject to restrictive covenants consistent with those discussed in Note 6.
(Page 30)
10. 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, 1999, the Company's long-term debt had a carrying value of
approximately $42.0 million and a fair value of approximately $43.7 million.
11. COMMITMENTS, CONTINGENCIES, AND REGULATORY
MATTERS
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 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.
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.
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.
According to EITF 97-4, entities should cease to apply Statement of Financial Accounting Standards
No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulations" when a deregulation plan is
in place and the terms are known. With respect to the generation portion of the Company's business, this
occurred in the fourth quarter of 1999, when the terms where substantially agreed upon by stipulations in
the MPUC's proceeding on revenue requirements, rate design and stranded costs in Docket 98-577. This
stipulation was approved by the MPUC on January 27, 2000. As more fully discussed in "Capacity
Arrangements", the Company sold all generating assets on June 8, 1999. Correspondingly, the Company
adopted SFAS 101 "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB
Statement No. 71" for the generation segment of its business in the fourth quarter of 1999. SFAS 101
requires a determination of impairment of plant assets under SFAS 121 "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" and the elimination of all effects of rate
regulation that have been recognized as assets and liabilities under SFAS 71. The Company has determined
no such impairment exists.
(Page 31)
The Company believes that its electric transmission and distribution operations continue to meet the
requirements of SFAS 71 and that regulatory assets associated with those operations as well as any
generation-related costs that the MPUC has determined to be recoverable from ratepayers also meet the
criteria. At December 31, 1999, $86.6 million of regulatory assets remain on the Company's books. These
assets will be amortized over various periods in accordance with the MPUC approved Phase II filing.
For further discussion of the specific impacts of the industry restructuring on the Company and related
ratemaking activity, see "MPUC Approves Elements of Rates Effective March 1, 2000" below.
MPUC Approves Elements of Rates Effective March 1, 2000
On October 14, 1998, and subsequently amended on February 9, 1999, August 11, 1999, and December
15, 1999, the Company filed its determination of stranded costs, transmission and distribution costs and rate
design with the MPUC. The Company's amended testimony supported its $95.7 million estimate of stranded
costs, net of available value from the sale of the generating assets, 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.
On October 15, 1999, the Company filed with the MPUC a Stipulation resolving the revenue
requirement and rate design issues for the Company's Transmission and Distribution (T&D) utility. This
Stipulation had been signed by the Public Advocate and approval was recommended by the MPUC Staff.
Under the Stipulation, the Company's total annual T&D revenue requirement will be $16,640,000, effective
March 1, 2000. This revenue requirement includes a 10.7% return on equity with a capital structure based
on 51% common equity. The Stipulation further provided that the precise level of stranded cost recovery
could not be determined until final determination of all costs associated with the sale of the Company's
generating assets, but did set forth some general principles concerning the Company's ultimate stranded
costs recovery, including agreement that the major components of the Company's stranded costs are
legitimate, verifiable and unmitigable, and therefore subject to recovery in rates. Furthermore, the
Stipulation allowed the 3.66% foregone revenue increase as a result of a rate plan Stipulation approved by
the MPUC in its April 6, 1999 Order in Docket 98-865 to be recovered through a reduction in the deferred
gain on the asset sale. The Stipulation also provided that the Company's recovery of unamortized
investment tax credits and excess deferred income taxes associated with the Company's generating assets
must await a final determination ruling from the IRS, which ruling was sought by Central Maine Power
Company (CMP). On December 1, 1999, the MPUC approved the October 15, 1999 Stipulation, as described
above. In early January, 2000, CMP received its ruling from the IRS which concluded that the unamortized
investment tax credits and excess deferred income taxes associated with the sale of the generating assets
could not be used to reduce customer rates without violating the tax normalization rules for Public utilities.
Therefore, the Company has recognized these excess deferred taxes in income, which amounted to an
increase in net income of approximately $389,000.
On January 27, 2000, the MPUC approved a Stipulation in Phase II of Docket No. 98-577 that provided
for the recovery in rates of the Company's stranded investment. The major element of the Phase II
Stipulation was the $12.5 million of stranded investment recoverable annually beginning March 1, 2000.
This revenue requirement includes a return on unrecovered stranded investment based on the capital
structure approved by the MPUC in its December 1, 1999 Order. The approved capital structure will consist
of 51% common equity with an authorized return on equity of 10.7%. The Phase II Stipulation also allowed
the Company to offset its unrecovered stranded investment in Seabrook by approximately $7 million,
representing an amount equal to 35% of the available value from the sale of the generation assets. The
parties to the Phase II Stipulation also resolved several rate design issues, principally the elimination of the
inclining block rate for residential customers. In addition, the Company was granted several accounting
orders incorporating certain accounting methodologies used in determining the elements of stranded costs.
The annual revenue requirement associated with the recovery of stranded costs will be reviewed every two
years.
With the award of the standard offer rate on November 18, 1999, and orders approving the Company's
T&D rates and stranded investment recovery rates described above, the MPUC has established all elements
of customer rates effective March 1, 2000, the beginning of deregulation in Maine.
After paying off debt with proceeds from the sale of the Company's generating assets, as required under
the Company's mortgage indentures, the Company projects that the percentage of common equity as a
component in its capital structure would exceed 51%. In order to manage its capital structure to limit
common equity to 51%, the MPUC, on November 17, 1999, approved the Company's request to repurchase
up to 500,000 shares of its common stock over a period of five years. The shares will be repurchased
through an open-market program.
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 provided our customers
with predictable rates until March 1, 2000, and shares operating risks and benefits between the Company's
shareholders and customers. As described in the "Industry Restructuring" and "MPUC Approves Elements
of Rates Effective March 1, 2000" above, March 1, 2000 is the beginning of industry restructuring and new
rates.
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 agreed that it would seek no other increases, for either
base or fuel rates, except as provided under the terms of the plan. There were no fuel clause adjustments for
the duration of the plan. The rate plan also provided 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 "Capacity Arrangements" below.
(Page 32)
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 permitted 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
provided 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.
For the final year of the rate plan beginning February 1, 1999, the Company filed on November 13,
1998, 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. On December 15, 1998, the
MPUC granted the Company's request to defer the increase to April 1, 1999, as well as extend the rate plan
by one month to February 29, 2000, to coincide with the start of retail competition in Maine.
In its April 6, 1999 Order, the MPUC approved a March 25, 1999 Stipulation between the Office of the
Public Advocate (OPA) and the Company. Under this Stipulation, customer rates would not increase on
April 1, 1999, if the MPUC approved the sale of the Company's generation assets. The approval of the
Stipulation also resolved certain issues associated with the treatment of capacity cost savings from the
closure of Maine Yankee under the Company's rate stabilization plan.
The principal provisions are as follows:
1. The Company is entitled to a 3.66% specified rate increase as of April 1, 1999. Rather than increase
customer rates, the Company will recognize the revenues that this increase would have generated
and, correspondingly, record a deferred asset on the Company's books of account. The parties to
the Stipulation also agreed to recommend the use in rates of available value from the asset sale
corresponding with the specified rate increase once the MPUC determines the Company's allowed
stranded cost recovery in Docket No. 98-577, Public Utilities Commission, Investigation of
Stranded Costs, Transmission and Distribution Utility, Revenue Requirements and Rate Design of
Maine Public Service Company.
2. The Stipulation also resolves a dispute over the determination of Maine Yankee replacement power
costs. The Stipulation allows the Company to continue to recognize and defer Maine Yankee
replacement power costs on an energy-only basis, offset by Wheelabrator-Sherman contract
restructuring savings, through the end of the rate plan. The Company agreed to begin amortizing on
April 1, 1999, Maine Yankee replacement power costs in the amount of $150,000 per month or a
total of $1,650,000 for the remaining eleven months of the rate plan.
3. With the Commission's approval of the generation asset sale, the parties agreed that the Company
would not increase retail rates on April 1, 1999, to reflect any increase under the Maine Yankee
replacement power provision of the rate plan. Any Maine Yankee deferred replacement costs will
be deferred, and, beginning on March 1, 2000, will be offset by a corresponding amount of available
value as allowed in Docket No. 98-577.
As described in "MPUC Approves Elements of Rates Effective March 1, 2000", above, the MPUC
approved a Stipulation providing for the recovery in rates of stranded investment, which includes the
deferrals allowed under the rate plan.
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, 1999 and 1998 are as follows:
(Dollars in Thousands)
1999 1998
Retail $43,136 $43,136
Accumulated Amortization (19,684) (18,261)
Retail, Net of Amortization $23,452 $24,875
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 4), the Company's
share of any retrospective premium would not exceed approximately $4.0 million or $.5 million annually,
without considering inflation indexing.
Capacity Arrangements
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 was required by the State's electric industry restructuring law. The gain from the asset
sale will reduce stranded cost revenue requirements, as discussed in "MPUC Approves Elements of Rates
Effective March 1, 2000" above.
(Page 33)
The Company consummated the sale to WPS-PDI on June 8, 1999 after receiving all of the major
regulatory approvals. The Company's 5% ownership in Maine Yankee was not part of the sale, since the
plant is being decommissioned. After paying Canadian, Federal and State income taxes, the remaining
proceeds, along with interest in the trust account, will be used to reduce the Company's debt by $22.4
million. The gain from the sale has been deferred, as required by the MPUC. The components of the
deferred gain are as follows:
(Dollars in Millions)
Gross proceeds $ 37.5
Settlement adjustments (.1)
Net proceeds 37.4
Net book value (11.5)
Excess taxes on sale of
Canadian Assets (3.4)
Transition costs, net (1.8)
Deferred RSP rate increase (1.3)
Other .5
Deferred gain * $ 19.9
* The $19.9 million deferred gain above is the $20.2 million "Deferred Gain and Related
Accounts" as of December 31, 1999 reduced by the remaining deferral of transition costs allowed
by the MPUC.
As a result of the deferral of the gain on sale of generating assets for financial statement reporting
purposes, certain of the above adjustments impact the statement of cash flows as follows:
Net book value of current assets and liabilities
purchased/assumed, principally inventory $ 446,000
Change in deferred regulatory costs representing
amounts offset against the purchase price
principally an RSP rate increase and excess
purchase power costs related to sale $2,445,000
Change in deferred regulatory costs representing
interest accrued on deferred gain $ 519,000
Upon liquidation of the subsidiary in December 1999, $14.1 million of the proceeds was transferred to
the first mortgage trustee for eventual paydown of long-term debt.
After the sale of the Company's generating assets in June, 1999, the Company purchased energy from
the new owners, under an agreement that expires February 29, 2000.
As part of the generating asset sale, the Company has entered into two indemnity obligations with the
purchaser, WPS-PDI. First, the Company will be liable, with certain limitations, for certain Aroostook
River flowage damage. This liability will continue for ten years after the sale and shall not exceed
$2,000,000 in the aggregate. Second, the Company has warranteed the condition of the sites sold to WPS-PDI, with an aggregate limit of $3,000,000 for two years after the date of sale, and five years after the sale
for environmental claims. The Company is unaware of any pending claims under either of these indemnity
obligations.
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).
During 1998 and early 1999 the active interveners, including among others the MPUC Staff, the Office
of the Public Advocate (OPA), the Company and other owners, the Secondary Purchasers, and a Maine
environmental group (the "Settling Parties"), engaged in extensive discovery and negotiations which
resulted in the filing of a settlement agreement with the FERC on January 19, 1999. A separate negotiated
settlement filed with the FERC on February 5, 1999 resolved 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. Both settlements were found to be in the Public
interest and approved by the FERC on June 1, 1999. The settlements constitute a full settlement of all
issues raised in the FERC proceeding including decommissioning-cost issues and issues pertaining to the
prudence of management, operation and decision to permanently cease operation of the Plant.
The primary settlement provided for Maine Yankee to collect $33.1 million in the aggregate annually,
effective August 1, 1999, including both decommissioning costs and costs related to Maine Yankee's
planned independent spent fuel storage installation (ISFSI). The 1997 FERC filing had called for an
aggregate annual collection rate of $36.4 million for decommissioning and the ISFSI, based on a 1997
estimate. Pursuant to the approved settlement the amount collected annually has been reduced to
approximately $25.6 million, effective October 1, 1999, as a result of 1999 Maine legislation allowing
Maine Yankee to (1) use for decommissioning the ISFSI funds held in trust under Maine law for spent-fuel
disposal, and (2) access approximately $6.8 million 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.
The 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
maximum allowed equity amounts, which resulted in a pro-rata refund of $9.3 million (including tax
impacts) to the sponsors on July 15, 1999. The Settling Parties also agreed 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.
(Page 34)
Under the Maine Agreement, the Company continued 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 settlement, no refunds would be
required, but such excess amounts would be credited to the customers to the extent required by the RSP.
Finally, 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 the maximum amount would be $4.1 million for
the period.
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. Beginning in May, 1998,
Maine Yankee replacement power costs have been offset by net savings from the restructured Purchase
Power Agreement with Wheelabrator-Sherman, in accordance with the rate plan stipulation. Beginning in
April, 1999 the Company began amortizing an additional $150,000 per month as part of a stipulation
described in "Four-Year Rate Stabilization Plan Approved" above. As of December 31, 1999, the Company
has a deferred Maine Yankee replacement power cost balance of approximately $3.0 million, subject to
recovery in accordance with the rate plan.
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 and
again in June, 1999, 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 regulation 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, 1999, is
carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of
$32.2 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. As discussed in the "MPUC Approves Elements of Rates Effective
March 1, 2000", above, the MPUC on January 27, 2000, approved a Stipulation providing for the recovery
of stranded investment, which includes the Company's share of Maine Yankee decommissioning expenses,
Maine Yankee replacement power costs and the remaining Maine Yankee investment.
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.
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
amended PPA has helped 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. Expenses under this contract during 1999, 1998 and 1997 were $14.2 million,
$13.8 million and $15.9 million, respectively.
The Company estimates its remaining commitment to purchase power under this contract to be $84.2
million from March 1, 2000 through 2006. The Company has entered a contract whereby WPS-PDI takes
delivery of the power through February 28, 2002 at market prices. The Company estimates that the
remaining stranded costs will be $58.7 million through 2006, assuming arrangements similar to the one with
WPS-PDI will be in place for that period.
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, as subsequently ordered by the MPUC in Docket 98-577, see "MPUC Approves Elements of Rates Effective March 1, 2000", above. 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. Expenses under this agreement during 1999
and 1998 were $7.8 million and $7.2 million, respectively.
(Page 35)
Construction Program
Expenditures on additions, replacements and equipment for the years ended December 31, 1999, 1998,
and 1997, along with 2000 estimated expenditures, are as follows:
(Dollars in Thousands)
2000 1999 1998 1997
(Unaudited Estimates)
Parent Company
Generation $ -- $ 12 $ 4 $ 92
Transmission 1,157 1,277 803 491
Distribution 3,162 2,342 2,226 1,636
General 907 1,072 712 425
Total Parent 5,226 4,703 3,745 2,644
Subsidiaries
Maine and New Brunswick -- -- -- 80
Energy Atlantic -- 61 -- --
Total $ 5,226 $4,764 $ 3,745 $ 2,724
12. QUARTERLY INFORMATION (unaudited)
Quarterly financial data for the two years ended December 31, 1999 is as follows:
(Dollars in Thousands Except Per Share Amounts)
1999 by Quarter
1st 2nd 3rd 4th
Operating revenues $17,469 $16,423 $15,391 $18,173
Operating expenses (14,980) (14,789) (14,868) (15,742)
Operating income 2,489 1,634 523 2,431
Interest charges (972) (985) (1,205) (1,074)
Other income-net 242 63 372 488
Net income (loss) $ 1,759 $ 712 $ (310) $ 1,845
Earnings (Loss) per common share $ 1.09 $ 0.44 $ (0.19) $ 1.14
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 (loss) $ 1,106 $ 22 $ (151) $ 1,276
Earnings (Loss) per common share $ 0.68 $ 0.01 $ (0.09) $ 0.79
(Page 36)
MAINE PUBLIC SERVICE COMPANY
and Subsidiaries (Unaudited)
All share information and per share amounts reflect the stock split on March 3, 1989.
Consolidated Financial Statistics
1999 1998 1997
Capitalization Including Bank Borrowings (year-end)
Debt (including amount due within one year) 55.11% 61.28% 57.82%
Preferred Stock (including amount due within one year) 0.00% 0.00% 0.00%
Common Shareholders' Equity 44.89% 38.72% 42.18%
Times Interest Earned - *
Before Income Taxes 2.73 2.02 0.14
After Income Taxes 1.94 1.52 0.39
Times Interest and Preferred Dividends Earned - *
After Income Taxes 1.94 1.52 0.39
Embedded Cost of Long-Term Debt (year-end) 7.91% 8.10% 7.96%
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 2.48 1.39 (1.35)
Extraordinary Items -- -- --
Net Income (Loss) 2.48 1.39 (1.35)
Dividends Per Share of Common Stock
Declared Basis 1.10 1.00 1.00
Paid Basis 1.05 1.00 1.21
Common Stock Dividend Payout Ratio - ** 44.35% 71.94% --
Book Value Per Share of Common Stock (year-end) 22.98 21.60 21.21
Market Price Per Share of Common Stock
High 19 1/8 17 3/16 18 3/8
Low 12 7/8 11 3/4 10 1/4
Close 17 3/8 15 1/4 12
Price Earnings Ratio (year-end) + 7.01 10.97 --
Number of Common Shareholders (year-end) 1,175 1,436 1,436
* 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.
(Page 37)
1996 1995 1994 1993 1992
1991 1990 1989
52.75% 49.92% 44.25% 45.83% 50.16% 53.01% 49.40% 43.12%
0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 4.02%
47.25% 50.08% 55.75% 54.17% 49.84% 46.99% 50.60% 52.86%
2.18 2.51 3.25 3.49 3.01 2.81 3.24 3.21
1.60 1.80 2.26 2.36 2.09 2.00 2.22 2.26
1.60 1.80 2.26 2.36 2.09 2.00 2.18 2.09
8.01% 9.36% 9.36% 9.14% 9.14% 9.28% 9.92% 9.71%
0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 9.74%
1,617,250 1,617,250 1,617,250 1,660,250 1,660,250 1,660,250 1,761,050 1,849,550
1.31 .57 2.99 3.19 2.93 2.62 2.58 2.71
1.31 (3.29) 2.99 3.19 2.93 2.62 2.58 2.71
1.84 1.84 1.84 1.78 1.76 1.68 1.68 1.575
l.84 l.84 l.84 l.76 1.74 1.68 1.66 1.55
140.46% 98.40% 61.54% 55.80% 60.07% 64.12% 65.12% 58.12%
23.55 24.09 29.22 28.02 26.61 25.44 24.38 23.39
22 3/8 23 7/8 27 3/8 31 1/4 26 7/8 26 3/8 23 3/8 24 7/8
16 7/8 19 7/8 20 1/2 25 5/8 24 1/4 20 3/4 19 1/2 20 5/16
18 1/8 21 3/8 20 3/4 25 7/8 25 7/8 26 3/8 22 1/4 22 3/8
13.84 -- 6.94 8.11 8.83 10.07 8.62 8.26
1,619 1,634 1,650 1,720 1,768 1,823 2,061 1,919
(Pie Chart on Page 36)
1999 Sources of Income
Millions of Dollars (Total $68.6)
and Percent of Total
Other Income
$3 Million [4.4%]
Residential
$21.7 Million
[31.6%]
Commercial
$19.5 Million [28.4%]
Industrial
$10.6 Million [15.5%]
Other Electric Sales
$13.8 Million [20.1%]
1999 Distribution of Income
Millions of Dollars (Total $68.6)
and Percent of Total
Wages and Employee Benefits
$7.1 Million [10.4%]
Taxes
$5 Million [7.3%]
Other Operating Expenses
$8.6 Million [12.5%]
Interest
$4.2 Million [6.1%]
Common Dividends
$1.8 Million [2.6%]
Retained Earnings
$2.2 Million [3.2%]
Fuel & Purchased Power
$39.7 Million [57.9%]
(Stack Chart on Page 37)
YEAR-END CAPITALIZATION
(Percent)
1995 1996 1997 1998 1999
Total Debt 49.92 52.75 57.82 61.28 55.11
Common Equity 50.08 47.25 42.18 38.72 44.89
(Page 38)
MAINE PUBLIC SERVICE COMPANY
and Subsidiaries (Unaudited)
Consolidated Operating Statistics
1999 1998 1997
Operating Revenues
Residential $21,707,886 $20,592,662 $20,391,688
Commercial and Industrial - Small 19,461,913 18,363,186 17,418,761
Commercial and Industrial - Large 10,596,252 10,249,381 9,452,158
Municipal Street Lighting 605,343 585,053 546,071
Area Lighting 279,715 276,029 268,208
Other Municipal and Other
Public Authorities 363,819 478,694 653,563
Other Electric Utilities 12,536,286 4,229,874 4,307,528
Other Operating Revenues 1,904,903 1,852,027 2,034,219
Total Operating Revenues $67,456,117 $56,626,906 $55,072,196
Number of Customers (average)
Residential 28,763 28,635 28,561
Commercial and Industrial - Small 5,690 5,630 5,586
Commercial and Industrial - Large 16 16 15
Municipal Street Lighting 41 39 39
Area Lighting 1,086 1,049 1,063
Other Municipal and Other
Public Authorities 3 4 5
Other Electric Utilities 7 8 11
Total Customers 35,606 35,381 35,280
Net Generation, Purchases and Sales
(thousands of kilowatt-hours)
Net Generation:
Steam 28,783 35,764 26,758
Hydro 81,543 123,288 107,734
Diesel (443) (800) (429)
Purchases:
Nuclear Generated -- -- --
Fossil Fuel Generated 835,211 501,007 496,888
Inadvertent Received (Delivered) (2,120) (4,049) (494)
Total 942,974 655,210 630,457
Losses, Unaccounted for and Unbilled 39,834 39,903 34,128
Company Use 1,192 1,414 1,695
Electricity Sold 901,948 613,893 594,634
Sales:
Residential 170,481 163,073 167,368
Commercial and Industrial-Small 183,424 173,168 168,976
Commercial and Industrial-Large 149,979 144,228 134,741
Municipal Street Lighting 1,800 1,762 1,676
Area Lighting 1,410 1,416 1,443
Other Municipal and Other Public Authorities 4,267 6,827 10,204
Other Electric Utilities 390,587 123,419 110,226
Total Sales 901,948 613,893 594,634
Average Use and Revenue Per
Residential Customer
Kilowatt-hours 5,927 5,695 5,860
Revenue $ 754.72 $ 719.14 $ 713.97
Revenue per Kilowatt-hour 12.73 cents 12.63 cents 12.18 cents
(Page 39)
1996 1995 1994 1993 1992 1991 1990 1989
$19,961,192 $19,080,662 $19,646,681 $19,669,749 $18,704,900 $19,194,469 $18,189,325 $18,537,902
16,420,167 15,723,439 15,614,453 15,177,992 13,787,720 13,991,693 12,708,677 13,379,207
10,111,758 9,437,409 9,225,131 9,554,566 8,891,123 10,105,693 10,115,772 9,785,058
538,890 524,616 517,793 512,439 499,814 512,640 505,063 573,351
273,985 272,896 271,115 269,925 261,984 267,518 262,845 288,378
710,106 903,370 2,105,933 3,597,514 3,761,815 3,977,098 3,611,220 3,736,851
6,893,598 7,573,360 8,481,483 9,188,561 8,150,094 7,328,914 9,649,398 10,980,817
2,354,469 1,762,974 2,505,496 2,505,466 2,626,190 2,460,062 1,701,167 (62,314)
$57,264,165 $55,278,726 $58,368,085 $60,476,212 $56,683,640 $57,838,087 $56,743,467 $57,219,250
28,515 28,385 28,300 28,220 28,102 28,052 27,983 27,737
5,541 5,465 5,418 5,364 5,261 5,205 5,108 4,940
15 15 16 16 15 15 15 17
38 38 38 38 38 38 38 38
1,059 1,048 1,048 1,061 1,075 1,091 1,114 1,155
5 5 8 8 8 8 8 8
10 9 9 8 7 7 7 8
35,183 34,965 34,837 34,715 34,506 34,416 34,273 33,903
10,201 22,867 18,559 26,456 33,509 28,868 59,252 91,361
168,993 121,252 118,759 148,719 130,407 135,619 176,832 106,571
(674) 1,046 (153) 169 (636) (178) (186) 2,664
249,083 9,718 326,334 282,199 263,313 307,769 253,321 369,315
372,431 508,266 290,172 288,487 300,930 246,172 289,177 217,166
741 (1,449) 651 (1,053) (2,232) 1,861 (151) 1,611
800,775 661,700 754,322 744,977 725,291 720,111 778,245 788,688
33,303 36,411 42,880 43,944 43,686 42,114 40,613 42,474
1,517 1,490 1,518 1,542 1,462 1,499 1,559 1,723
765,955 623,799 709,924 699,491 680,143 676,498 736,073 744,491
169,298 168,640 175,685 176,732 176,814 176,028 178,011 178,668
163,804 165,914 167,485 162,949 155,267 149,709 146,881 145,364
134,588 128,478 127,327 135,029 129,981 139,931 155,782 145,307
1,658 1,655 1,642 1,630 1,864 2,336 2,697 2,722
1,418 1,457 1,472 1,482 1,538 1,591 1,643 1,580
10,090 11,747 28,621 53,021 58,388 57,687 57,034 59,190
285,099 145,908 207,692 168,648 156,291 149,216 194,025 211,660
765,955 623,799 709,924 699,491 680,143 676,498 736,073 744,491
5,937 5,941 6,208 6,263 6,292 6,275 6,361 6,442
$ 700.02 $ 672.21 $ 694.23 $ 697.01 $ 665.61 $ 684.25 $650.01 $ 668.35
11.79 c 11.31c 11.18c 11.13c 10.58c 10.90c 10.22c 10.38c
(Page 40)
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
(Inside Back Cover)
Executive Officers
Paul R. Cariani
President & Chief Executive Officer
Frederick C. Bustard
Vice President
Power Delivery
Larry E. LaPlante
Vice President, Treasurer and
Chief Financial Officer
Stephen A. Johnson
Vice President
Energy Atlantic & General Counsel
Peter C. Louridas
Assistant To The President
William L. Cyr
Assistant Vice President
Power Delivery
Michael A. Thibodeau
Assistant Vice President
Human Resources
Kurt A. Tornquist
Controller, Assistant Treasurer
& Assistant Secretary
Walter J. Elish
Director of Economic Development
Transfer Agent
The Bank of New York
Shareholder Relations Dept. - 11E
P. O. Box 11258, Church Street Station
New York, NY 10286
Tel. No. 1-800-524-4458
E-Mail: Shareowner-svcs@bankofny.com
Stock Registrar
The Bank of New York
Annual Meeting
Tuesday, May 9, 2000
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.mainepublicservice.com
E-Mail: mainepub@ mfx.net
Exhibit 99(w)
STATE OF MAINE Docket No. 98-584
PUBLIC UTILITIES COMMISSION
April 5, 1999
MAINE PUBLIC SERVICE COMPANY ORDER APPROVING SALE
Petition for Sale of Generating Assets OF ASSETS
WELCH, Chairman; NUGENT and DIAMOND, Commissioners
______________________________________________________________
I. SUMMARY
We approve the sale of generation assets from Maine Public Service Company
(MPS, or the Company) to WPS Power Development, Inc. (WPS). We find and certify
that the generation facilities to be sold to WPS should be granted Exempt Wholesale
Generator (EWG) status by the Federal Energy Regulatory Commission (FERC). We
also find that Maine law grants to MPS, or its predecessors, rights, privileges or
immunities that are generation assets required to be divested by section 3204.
II. BACKGROUND
As a condition of restructuring, electric utilities must, with limited exceptions,
divest all generation assets and all generation-related business activities by March 1,
2000. 35-A M.R.S.A. section 3204(1). For MPS, the limited exceptions constitute a
significant portion of its generation assets. The limited exceptions include contracts with
qualifying facilities (QFs) (section 3204(1)(A)) and ownership of facilities located outside
the United States (section 3204(1)(C)). Thus, MPS is not obligated to divest its
contractual entitlement to the output of the 18.1 MW biomass plant owned by
Wheelabrator-Sherman Energy Company or the 34.5 MW Tinker Station which includes
33.5 MW of hydro-electric capacity and 1MW of diesel capacity.1
MPS must divest in accordance with a plan approved by the Commission. MPS
hired Stone and Webster Management Consultants, Inc. to assist the Company in its
sale efforts. MPS and Stone and Webster developed an auction or bid process. The
auction included the opportunity to purchase all MPS generation assets, including the
Tinker Station and the contractual entitlement to the output of the Wheelabrator
Sherman QF Plant. By Order dated February 20, 1998, the Commission approved the
divestiture plan developed by MPS with the assistance of Stone and Webster. Maine
Public Service Company, Docket No. 97-670 (Feb. 20, 1998).
1 Pursuant to 35-A M.R.S.A. section 3204(4), MPS is required to sell periodically the
rights to the capacity and energy from the generation assets not divested. See also,
chapter 307 of the Commission's Rules.
Order Approving Sale of Assets - 2 - Docket No. 98-584
On July 7, 1998, MPS selected WPS Power Development, Inc. (WPS) as the
winning bidder for most of the assets offered. MPS and WPS entered into an Asset
Purchase Agreement (APA) whereby MPS agreed to transfer to WPS the following
generation assets:
1. The Millinocket Lake Storage Dam;
2. The Squa Pan Dam, including storage and generating capacity;
3. The Caribou Generating Station;
4. The Flo's Inn Generating Station and the Houlton Generating Station
(diesel units);
5. The Tinker Generating Station and associated transmission, owned and
operated by Maine and New Brunswick Electrical Power Company,
Limited (M&NB), a wholly-owned subsidiary of MPS; and
6. MPS's 3.3455% interest in the Wyman Unit #4, oil-fired plant in Yarmouth,
Maine.
MPS and WPS executed the following additional agreements which are
referenced in the APA:
1. A Buy-back Agreement, pursuant to which MPS will buy back from WPS
the output of the assets being purchased by WPS from the date of closing
to March 1, 2000;
2. Two Interconnection Agreements, one each for the U.S. and Canadian
assets being sold; and
3. A Continuing Site Agreement for certain of the assets being sold.
MPS rejected all bids for the contractual entitlement to the output of the
Wheelabrator-Sherman plant. Because 35-A M.R.S.A. section 3204(1) does not
require the divestiture of the Wheelabrator-Sherman contract, the proposed sale to
WPS constitutes the complete divestiture required by law.
On August 7, 1998, MPS filed a petition seeking authorization to sell its
generation assets to WPS. MPS's filing includes both confidential and non-confidential
testimony on the auction process and the details of the sale, as well as the APA, and
the buy-back and other agreements between MPS and WPS. After providing notice
and opportunity to intervene, the Examiner granted the petitions to intervene of the
Order Approving Sale of Assets - 3 - Docket No. 98-584
Public Advocate (OPA), Houlton Water Company (HWC), and the late-filed petition on
behalf of McCain Foods, Inc. (McCain).
In its February 20, 1998 Order approving MPS's divestiture plan, the
Commission noted that the lack of any direct electrical connection between MPS and
the rest of New England presented unique market power issues that might inhibit the
development of an adequate competitive retail market for electricity in northern Maine.
The Commission directed MPS to address the market power issues when it filed for
authorization to sell its generation assets. In its prefiled testimony, MPS presents
evidence and argument as to why the Company's indirect interconnection to New
England through New Brunswick and the MEPCO line, and Canadian sources of supply
to MPS through New Brunswick, should allow the development of an adequate retail
competitive market for electricity in northern Maine.
Intervenor testimony was prefiled by the OPA and HWC. HWC presented
testimony that northern Maine's interconnection to New England through New
Brunswick does jeopardize the development of an adequate retail competitive retail
market and recommended that MPS not be allowed to divest itself of its generation
assets until the necessary conditions for retail competition have been undertaken. The
OPA presented testimony that, under certain theoretical conditions, owners of
generation could manipulate and possibly exert undue control over prices in the market
not only in northern Maine, but potentially elsewhere in New England. The OPA's
witness recommended that the asset transfer to WPS be approved but that WPS be
required to bid for standard offer service at "truly competitive market prices." This
recommendation would be implemented either by requiring WPS to extend the terms of
the buy-back agreement with MPS beyond February, 2000 or by capping generation
prices at the long run marginal cost of new market entry.
On December 10, 1998, the Examiner issued a report prepared by the
Commission's consultant that served as the bench analysis. The consultant found that
the proposed sale to WPS created ratepayer benefits. However, the consultant raised
certain issues about MPS's analysis in choosing the WPS bid. The issues concerned
whether: 1) MPS needed to or should retain its diesel units for voltage support; 2)
WPS's bid for Wyman 4 was comparable to other recent Wyman 4 bids; and 3) MPS
erred by using embedded costs for values of plants not sold when developing bid
comparison analysis.
MPS responded to the intervenor testimony and bench analysis in prefiled
rebuttal testimony on January 20, 1999.
No intervenor filed testimony or raised issues at hearing or in briefs concerning
MPS's auction process or MPS's selection of WPS as the winning bidder. It thus
appears that the intervenors do not object to a finding that MPS pursued all reasonable
means to reduce its potential stranded costs by the conduct of its auction and the sale
of the generating assets to WPS.
Order Approving Sale of Assets - 4 - Docket No. 98-584
III. DISCUSSION
We have reviewed the evidence and issues raised in the bench analysis
concerning the auction process and MPS's decisions during that process. We agree
with MPS's assertion that the diesel units are not necessary for T&D efficiency reasons.
We accept MPS's explanation in its rebuttal testimony as to the reasonableness of the
value received for its share of Wyman #4.2
Concerning the use of embedded costs in its bid comparison analysis, MPS
admits, at least in part, that such use led to inaccurate comparisons. There is, however,
disagreement about the measure of that inaccuracy. Based on the bench analysis, the
inaccuracy could result in another bidder's bid for MPS's hydro assets being worth
about $300,000 more than WPS's bid for the assets. However, even accepting the
validity of the bench analysis calculation, the additional costs of a second auction and
closing that would be necessary for the non-hydro assets would likely approach or
exceed the $300,000 and thus eliminate any additional value from choosing the other
bidder. We will thus approve MPS's choice to sell to WPS and find that MPS
reasonably acted to reduce its potential stranded cost by its auction and
choice of WPS as the winning bidder.
Much of the market power focus in this proceeding has arisen from two reports
prepared on behalf of the Commission for the Joint Standing Committee on Utilities and
Energy of the Maine Legislature. The Legislature directed the Commission to conduct
a study "to determine the most effective and efficient means" that customers of Maine
utilities not directly connected to the New England electric grid "are able to take full
advantage of retail access." 35-A M.R.S.A. section 3206(3). This report, entitled:
Competition and Market Power in the Northern Maine Electricity Market, prepared for
the Commission by Tim Woolf and Bruce Biewald, Synapse Energy Economics, and
Duncan Glover, Experiment Failure Analysis, was submitted to the Committee on
December 1, 1998 and was made part of the record in this proceeding.
The effect of market power on the development of the competitive retail electric
market in northern Maine was comprehensively reviewed in the joint Commission and
Attorney General Final Report on a Study of Market Power Issues Raised by Retail
Competition on the Maine Electric Utility Industry (Joint Report), prepared pursuant to
P.L. 1997, ch. 447 (118th Legis. 1997) and also submitted on December 1, 1998 and
made part of the record. The Joint Report noted the potential for an adversely high
level of market power in northern Maine, arising because:
The market is dominated by the New Brunswick Power
Corporation (NBP), which controls transmission access to
northern Maine. NBP transmission is unsupervised by any
2 We do not describe that explanation in this Order because it contains confidential bid
information.
Order Approving Sale of Assets - 5 - Docket No. 98-584
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.
Joint Report at 59. The Joint Report also cites a transmission constraint and the lack of
access to a well designed spot market as factors which aggravate the market power
problems.
Presented with these conclusions, the Joint Report opined that "the question of
whether retail choice in northern Maine should be postponed must be confronted." Id.
The Report concluded, however, that "postponement should be a last resort" and that
"[o]ther, less drastic remedies . . . should be implemented in the first instance." Id.
The Joint Report suggested that, until the Province of New Brunswick regulates
New Brunswick Power Corporation's (NBP or NB Power) transmission tariff, the
northern Maine T&D utilities should contract with NBP for tie-line interruption service
and needed ancillary services. The Joint Report also suggested NBP should offer to
contract with the T&Ds to provide transmission services at a fixed rate. Preferably, the
agreed price should be equal to NBP's lower "out" rate, rather than its higher "through"
rate. Joint Report at 77. According to the Joint Report, the effect of such contracts
should be to give any party interested in marketing power in northern Maine the ability
to do so on the basis of non-firm imports over the MEPCO line backed by NBP's "tie-line interruption service" together with needed ancillary services. These contracts
"would effectively remove the south-to-north constraint on the MEPCO line, and
significantly improve northern Maine's access to generators in New England." Id. at 74.
These contracts might also permit the "beneficial influence of New England spot market
pricing to be felt in northern Maine." Id. at 80.
To facilitate a contractual agreement that would mitigate market power problems,
the Commission invited the affected and interested parties to meet to discuss the
matter: NB Power, the Maine utilities connected to the New England grid only through
NB Power (MPS, HWC, Eastern Maine Electric Cooperative, Inc. and Van Buren Light
and Power District, collectively referred to as the "northern Maine utilities), the OPA and
Hydro-Quebec. As a direct result of the meeting of those parties at the Commission on
December 17 and 18, 1998, NBP and the northern Maine utilities have negotiated a
Products and Services Agreement, filed on February 22, 1999.
Under the Products and Services Agreement, NB Power agrees to supply: (1)
tie-line interruption service, on a firm or non-firm basis, to any northern Maine utility
requiring it; (2) ancillary services to any northern Maine utility; (3) transmission services
through New Brunswick to any northern Maine utility at a fixed rate equal to the current
"out" rate, which rate can be increased only by authorization of the proper New
Brunswick regulatory authority; and (4) bona fide offers of energy and capacity and
Order Approving Sale of Assets - 6 - Docket No. 98-584
other electrical products and services to any customer of any northern Maine utility.
Items (1) and (2) shall be available for a price equal to NB Power's actual cost plus a
reasonable contribution to NB Power's fixed costs. The Agreement continues in effect
unless canceled by all the parties or by this Commission. All aspects of the Agreement
are subject to impartial arbitration in case of dispute. The Agreement contemplates that
the northern Maine utilities will transfer these services at cost to competitive electricity
providers.
After the northern Maine utilities entered into the Products and Services
Agreement, MPS, HWC and the OPA filed a Partial Stipulation in this proceeding. The
stipulating parties agree that the Products and Services Agreement represents an
acceptable mitigation of the market power problems identified by the two Commission
Reports. The stipulating parties further agree that access to northern Maine's electrical
markets exclusively through NB Power's transmission system and over the MEPCO line
is no longer a substantial barrier to the development of an adequate retail market for
electricity in northern Maine. The stipulating parties therefore agreed that market power
issues do not prevent the Commission from approving the proposed sale of MPS's
generation assets to WPS.
McCain is the only party not to join the stipulation. In comments, McCain states
that it does not object to approval of the stipulation, "provided such approval properly
describes the remaining need for actual interconnection of northern Maine to the
electric grid of the United States and contains certain conditions to achieve that
objective . . . ." In McCain's view, the arrangements made in the Products and Services
Agreement should be viewed as transitional. The transitional, contractual mitigation of
NB Power's market power is acceptable to McCain provided that the Commission's
order expressly recognizes the "interim and transitional nature" of the Products and
Service Agreement; that MPS and the other northern Maine utilities "continue to be
obligated in good faith, to cooperate in efforts of the Commission ... to secure a
permanent transmission access to northern Maine"; that MPS "shall be obligated to
seek a resolution to the current absence of transmission access" to the rest of the New
England; and last, that MPS be required to set aside $1 million of the asset sale
proceeds "to fund the exploration and development of a resolution of the absence of
transmission access to northern Maine."
We agree that the Products and Services Agreement between NB Power and
the northern Maine utilities mitigates market power concerns to a significant extent and,
as a result, it is reasonable to allow the sale of MPS assets. We therefore need not
decide whether MPS should be authorized to sell its generation assets in the absence
of remedies provided by the Products and Services Agreement. We note that this
particular sale of assets does not increase market concentration. Without the Products
and Services Agreement, the issue would have come down to whether the retention of
Tinker Station in order to hedge against future market power-driven price increases
would have outweighed the benefits of reduced stranded costs from the sale of Tinker.
Although the Power and Services Agreement does not eliminate all market power
Order Approving Sale of Assets - 7 - Docket No. 98-584
potential, we agree with the stipulating parties that the mitigating effect of the
agreement removes the need to consider the retention of Tinker as a hedge against
market power. Therefore, the sale to WPS is in the public interest.
We do not believe that the public interest requires the conditions sought by
McCain, at least in the form advocated by McCain. As filed, the Product and Services
Agreement terminates only with the consent of parties to the Agreement or by Order of
the Commission. We are not certain of the other solutions that make the Agreement
"interim and transitional" and therefore see no advantage to labeling the Agreement as
such. We do agree, however, that the situation in northern Maine is developing and that
consideration of a direct transmission link to the rest of New England at some point in
the future may be appropriate. We note that the northern Maine T&D utilities will retain
a public utility obligation to assure that reasonable transmission access is available so
that power can be safely and economically delivered to their customers. McCain has
apparently decided that an MPS transmission connection to the New England grid is
the only permanent solution to NB Power's market power. While we agree that the
Product and Services Agreement may not solve all potential market power problems,
and that a transmission connection to MPS may warrant further study, we are not
prepared to require MPS to set aside $1 million to study transmission access. At the
time further study or construction is found to be appropriate, funding sources (either
through utilities or otherwise) will be determined.
MPS requests the Commission to issue Exempt Wholesale Generator (EWG)
findings with the Order Approving the Sale of Assets. WPS plans to file applications for
EWG determinations with the FERC. Because the facilities to be sold were reflected in
rates on October 24, 1992, under federal law, the Maine Commission must certify that
allowing the facilities to be eligible: (1) will benefit consumers; (2) is in the public
interest; and (3) does not violate Maine law.
We have concluded that the transfer of the assets to WPS is in the public
interest. Consumers will benefit by the implementation of the Legislature's requirements
of separation of generation from transmission and distribution, as well as by the
reduction in stranded costs. The assets are transferred because of state law, obviously
not in violation of state law. Because state law separates generation from transmission
and distribution and will remove generators from the definition of electric utility, allowing
the transferred facilities to be eligible facilities: (1) will benefit consumers; (2) is in the
public interest; and (3) does not violate Maine law.
During its 1998 session, the Maine Legislature passed a law authorizing utilities
to convey their generation-asset-related rights, privileges and immunities which are
required to be divested. The new law, codified at 35-A M.R.S.A. section 3204(8),
authorizes the transfer of generation-asset-related rights, privileges and immunities, but
only after (1) the utility provides to the Commission a copy of the law granting the rights
and a description of the proposed transfer and (2) the Commission specifically finds that
the law grants rights, privileges or immunities that are generation assets required to be
Order Approving Sale of Assets - 8 - Docket No. 98-584
divested or that are necessary to the ownership or operation of generation assets
required to be divested. On August 7, 1998, MPS provided a copy of laws that grant to
MPS (or its predecessors) the rights, privileges or immunities that MPS believes are
generation-asset-related and that MPS proposes to transfer to WPS.
The Gould Electric Company obtained authorization from the Maine Legislature
to store water and construct dams in certain waters in the State of Maine. P.&S.L.
1921, ch. 111. This authority was transferred to MPS, which was also thereby
authorized to develop water power on the Aroostook River. P.&S.L. 1949, ch. 78. The
rights and privileges granted under these Laws are necessary to the ownership of the
Millinocket Lake Storage Dam and the Squa Pan Dam since they provide a legal
authority for the construction, operation and/or ownership of these properties. The
Commission finds that these statutory rights are necessary to the ownership or
operation of generating assets being sold by MPS to WPS.
Accordingly, we
O R D E R
That the sale of Maine Public Service Company's assets to WPS Power
Development, Inc., pursuant to the Asset Purchase Agreement entered into on July 7,
1998 between Maine Public Service Company and WPS Power Development, Inc., is
authorized.
Dated at Augusta, Maine, this 5th day of April, 1999.
BY ORDER OF THE COMMISSION
/s/ Dennis L. Keschl Dennis L. Keschl
Administrative Director
COMMISSIONERS VOTING FOR: WELCH
NUGENT
DIAMOND
This document has been designated for publication.
Order Approving Sale of Assets - 9 - Docket No. 98-584
NOTICE OF RIGHTS TO REVIEW OR APPEAL
5 M.R.S.A. section 9061 requires the Public Utilities Commission to give each
party to an adjudicatory proceeding written notice of the party's rights to review or
appeal of its decision made at the conclusion of the adjudicatory proceeding. The
methods of adjudicatory proceedings are as follows:
1. Reconsideration of the Commission's Order may be requested under
Section 6(N) of the Commission's Rules of Practice and Procedure (65-407 C.M.R.11) within 20 days of the date of the Order by filing a petition
with the Commission stating the grounds upon which consideration is
sought.
2. Appeal of a final decision of the Commission may be taken to the Law
Court by filing, within 30 days of the date of the Order, a Notice of Appeal
with the Administrative Director of the Commission, pursuant to 35-A
M.R.S.A. section 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. section 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.
STATE OF MAINE
PUBLIC UTILITIES COMMISSION Docket No. 98-584
April 30, 1999
MAINE PUBLIC SERVICE COMPANY ORDER ON MOTION
Petition for Sale of Generating Assets TO AMEND
WELCH, Chairman; NUGENT and DIAMOND, Commissioners
_____________________________________________________________
Maine Public Service Company (MPS), on its own behalf and on behalf of WPS
Power Development, Inc., has moved for reconsideration of the Order in this case
approving divestiture, dated April 5, 1999. Basically, MPS has requested that we
amend the Order by making further specific findings under 35-A M.R.S.A. section
3204(8), beyond those made in the initial order. For the reasons set forth below, we
grant the motion.
We have now been supplied with certain additional Private and Special Laws
under which Maine Public Service and its predecessors were granted rights necessary
to the ownership or operation of MPS' generating assets. These laws are as follows:
Necessary to the Millinocket Lake Storage Dam
P.& S.L. 1943, ch. 84, which authorizes a specific height of water at the
Millinocket Lake Dam.
Necessary to the Caribou Dam
P.& S.L. 1887, ch. 237, which authorized MPS' predecessor to construct the
Caribou Dam for purposes of water storage.1
P.& S.L. 1893, ch. 237, granting electrical generation rights to MPS' predecessor
at Caribou.
P.& S.L. 1895, ch. 92, granting electric generation rights to MPS' predecessor at
Caribou.
1 Rights to supply public water were also granted by this law, but are not
pertinent to this proceeding because they were transferred to Caribou Water Works
Corporation in 1943.
Order on Motion to Amend - 2 - Docket No. 98-584
P.& S.L. 1935, ch. 15 granting electrical generation rights to MPS' predecessor
at Caribou.
P.& S.L. 1917, ch. 203, section 7, authorized Gould Electric Company (now
MPS) to purchase the rights and franchises of other utilities; MPS
purchased the Caribou Dam in 1943 and since then has exercised rights
at Caribou under this law and under the above laws.
The Commission makes the following factual findings:
Millinocket Lake Dam
Rights under P.&S.L. 1943, ch. 84 authorize a specific heights of water at the
Millinocket Lake Dam. Therefore, they themselves are generation assets required to be
divested under the electric utility divestiture statute and are necessary to the ownership
and operation of the assets at Millinocket Lake which are required to be divested under
that statute.
Caribou Dam
The rights under the Private and Special laws, P.& S.L. 1887, ch. 237;
P.& S.L. 1893, ch. 380; P.& S.L. 1895, ch. 92; and P.& S.L. 1935, ch. 15 authorize
ownership, construction and operation of the Caribou Dam for electrical power
generation. Therefore, they themselves are generation assets required to be divested
under the electric utility divestiture statute and are necessary to the ownership and
operation of the assets at Caribou which are required to be divested under that statute.
MPS's right to acquire other utilities under P.&S.L. 1917, ch. 203, section 7,
enable it today to exercise the rights of its predecessors at Caribou set forth in the
above laws. Therefore, to that extent they also are necessary to the operation of the
Caribou Dam and are generation assets required to be divested under 35-A M.R.S.A.
section 3204 state and are necessary to the ownership and operation of the assets at
Caribou which are required to be divested under the same statute.
Maine Public Service Company will retain all those Private and Special Law
rights related to distribution and transmission of electricity.
Accordingly, we
O R D E R
That the above factual findings supplement the Order of April 5, 1999 in this
case.
Order on Motion to Amend - 3 - Docket No. 98-584
Dated at Augusta, Maine, this 30th day of April, 1999.
BY ORDER OF THE COMMISSION
/s/ Raymond Robichaud
Raymond Robichaud
Assistant Administrative Director
COMMISSIONERS VOTING FOR: Welch
Nugent
Diamond
Order on Motion to Amend - 4 - Docket No. 98-584
NOTICE OF RIGHTS TO REVIEW OR APPEAL
5 M.R.S.A. section 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. section 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. section 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(x)
87 FERC paragraph 62,053
DC-A-1
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Maine Public Service Company ) Docket No. EC99-29-000
PDI New England, Inc. )
ORDER AUTHORIZING DISPOSITION
OF JURISDICTIONAL FACILITIES
(Issued April 14, 1999)
On February 3, 1999, Maine Public Service Company (Maine Public) filed, and on March
2, 1999, PDI New England, Inc. (PDI-NE) joined, an application pursuant to section 203 of the
Federal Power Act (FPA)(1) requesting Commission authorization for Maine Public to sell certain
jurisdictional facilities to PDI-NE as the designated purchaser for WPS Power Development, Inc.
(PDI). The proposed transaction is part of an overall sale of interests in several generating units
owned by Maine Public and its subsidiary, Maine and New Brunswick Electrical Power
Company, Ltd. (MNB), to subsidiaries of PDI under a state-mandated divestiture of Maine
Public's generation assets. The jurisdictional facilities to be sold include the step-up
transformers associated with the generating assets to be sold to PDI-NE.(2)
Maine Public is a Public utility under the FPA. Maine Public is engaged in the sale,
transmission and distribution of electric energy and related services in northern Maine. Maine
Public has two wholly-owned subsidiaries: (1) MNB, which is an electric utility incorporated in
the province of New Brunswick, Canada, and (2) Energy Atlantic, LLC, which is a power
marketer authorized by the Commission to engage in wholesale sales at Market-based rates.(3)
Docket No. EC99-29-000
Through MNB, Maine Public owns the Tinker Generating Station and associated transmission
facilities located in New Brunswick Canada.
PDI, which is a wholly-owned subsidiary of WPS Resources Corporation (WPS), is
engaged in the acquisition, development and operation of energy assets. WPS , in turn, is an
exempt public utility holding company. Among WPS' other energy-related subsidiaries are: (1)
Wisconsin Public Service Corporation, which is a natural gas and electric Public utility serving
portions of northeastern Wisconsin and the Upper Peninsula of Michigan; and (2) Upper
Peninsula Power Company, which is an electric utility serving portions of the Upper Peninsula of
Michigan. PDI-NE and PDI Canada, Inc. (PDI-Can) are wholly-owned subsidiaries of PDI
organized for the purpose of acquiring Maine Public's generation assets.(4)
As part of its divestiture plan, Maine Public entered into an Asset Purchase Agreement
with PDI under which it will sell to PDI-NE the following generating facilities located in
northern Maine: (1) the Millinocket Lake Storage Dam; (2) the 1.4 MW Squa Pan Generating
Station and Storage Dam; (3) the 30.9 MW Caribou Generating Station; and (4) the 4.2 MW
Flo's Inn Diesel Generation Station and Houlton Diesel Generating Station. Maine Public also
will sell to PDI-NE its 3.3455 percent ownership interest in Wyman 4, which is located in
southern Maine. In addition, Maine Public proposes to sell to PDI-Can, as the designated
purchaser for PDI, the Tinker Generating Station and associated transmission assets owned by
MNB in New Brunswick, Canada.
Notice of the application was published in the Federal Register with comments due on or
before March 5, 1999. On March 2, 1999, PDI-Can and PDI-NE filed a joint motion to
intervene.(5) On March 5, 1999, Houlton Water Company (Houlton) filed a motion to intervene
raising no substantive issues. Pursuant to Rule 214 of the Commission's Rules of Practice and
Procedure,(6) the timely unopposed motions to intervene serve to make PDI-Can, PDI-NE, and
Houlton parties to this proceeding.
Docket No. EC99-29-000
Maine Public contends that the proposed transaction is consistent with the Public interest
and will not adversely affect competition, rates, or regulation. With respect to competition,
Maine Public states that PDI is a new market participant that currently has no transmission or
generation assets in New England. Maine Public also notes that the Commission has found that
ownership of these generation assets did not provide Maine Public with market power.(7)
Furthermore, Maine Public asserts that the proposed transaction will not have an adverse
effect on rates. According to application, Maine Public currently serves two wholesale
customers, Van Buren Light and Power Company and Eastern Maine Electric Cooperative, under
power sales agreements that terminate on December 31, 2000. According to the application,
upon closing of the proposed transaction until March 1, 2000, Maine Public will buy power from
PDI to serve Maine Public's wholesale customers, and after March 1, 2000, Maine Public will
obtain power in the market to serve its wholesale customers and other customers under contract.
In any event, Maine Public commits that its wholesale customers will be held harmless.(8)
Finally, Maine Public contends that the proposed transaction will have no adverse effect
on federal regulation and is necessary to comply with state law.
After consideration, it is concluded that the proposed transaction is consistent with the
public interest and is hereby authorized, subject to the following conditions:
- The proposed transaction is authorized upon the terms and conditions and for the
purposes set forth in the application;
- the foregoing authorization is without prejudice to the authority of the
Commission or any other regulatory body with respect to rates, service, accounts,
valuation, estimates or determinations of costs or any other matter whatsoever
now pending or which may come before the Commission;
- Nothing in this order shall be construed to imply acquiescence in any estimate or
determination of cost or any valuation of property claimed or asserted;
Docket No. EC99-29-000
(4) The Commission retains authority under sections 203(b) and 309 of the Federal
Power Act to issue supplemental orders as appropriate; and
- Maine Public shall promptly notify the Commission when the disposition of
jurisdictional facilities is consummated.
Authority to act on this matter is delegated to the Director, Division of Opinions and
Corporate Applications, pursuant to 18 C.F.R. section 375.308. This order constitutes final
agency action. Requests for rehearing by the Commission may be filed within thirty (30) days of
the date of the issuance of this order, pursuant to 18 C.F.R. section 385.713.
/s/ Michael A. Coleman
Director
Division of Opinions
And Corporate Applications
Exhibit 99(y)
89 FERC paragraph 61,179
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: James J. Hoecker, Chairman;
Vicky A. Bailey, William L. Massey,
Linda Breathitt, and Curt Hébert, Jr.
Northern Maine Independent System Docket No. ER99-4225-000
Administrator, Inc.
ORDER ACCEPTING NORTHERN MAINE INDEPENDENT SYSTEM
ADMINISTRATOR'S FILING AND GRANTING STATUS AS A
REGIONAL TRANSMISSION GROUP
(Issued November 15, 1999)
On August 25, 1999, Northern Maine Independent System Administrator, Inc. (Northern
Maine ISA) submitted a filing under section 205 of the Federal Power Act (FPA),(9) establishing
an independent system administrator in Northern Maine.(10) Northern Maine ISA also asks that the
Commission find that it is a Regional Transmission Group (RTG) as defined in the
Commission's regulations.(11) In this order, we accept the Northern Maine ISA's filing and grant
the Northern Maine ISA's request for RTG status.
Docket No. ER99-4225-000 -2-
I. Background
Northern Maine ISA explains that it was created in response to the mandate of the
legislature of the State of Maine that effective retail competition be available to all of that state's
electricity consumers by March 1, 2000.(12) Northern Maine ISA states that shortly after enactment
of the retail electric competition mandate in 1997, Maine Public Service Company (Maine Public
Service), Houlton Water Company (Houlton), Eastern Maine Electric Cooperative, Inc. (EMEC),
and Van Buren Light and Power District (Van Buren) began a collaborative process open to all
stakeholders in Northern Maine, to Canada's New Brunswick Power Corporation (New
Brunswick Power) and to other potential stakeholders in the New England and eastern Canadian
region. The process evolved to include the active participation of the four initial entities,
representatives of each segment of the Northern Maine electric market, including large
customers, generators, marketers, brokers, aggregators or other entities legally entitled to sell
electric energy, capacity or other ancillary services to the public at retail (called Competitive
Electricity Providers (CEPs)), the Maine Public Utilities Commission (Maine Commission), the
Maine Attorney General, and the State of Maine Public Advocate (Maine Public Advocate) on
behalf of all other electric consumers in Northern Maine. Northern Maine ISA states that its
filing in this proceeding is a product of that process.(13)
Northern Maine ISA states that its formation is intended to facilitate the development and
implementation of retail electric competition in a geographically broad, but electrically isolated,
area in the northern-most part of the State of Maine.(14) The electric system in Northern Maine is
not directly interconnected with the rest of New England, any New England Power Pool
(NEPOOL) participant, or any other domestic electric system; its participants are not NEPOOL
participants and do not participate in ISO New England. The region's only access to the electric
system that serves the remainder of New England is through the transmission facilities of
Canada's New Brunswick Power, a statutory body created by the legislature of the Province of
New Brunswick Power, Canada, to serve the electric energy needs of that province. More
specifically, Maine Public Service can access NEPOOL utilities through New Brunswick Power
which is, in turn, interconnected with Maine Electric Power Company (Maine Electric), a
transmission only company that is jointly owned by a number of New England utilities, including
Maine Public Service.
Docket No. ER99-4225-000 -3-
Northern Maine ISA states that, given New Brunswick Power owns significant generation
in the region as well as the transmission facilities that connect Maine Public Service and EMEC
with each other and with the NEPOOL grid, a central aspect of Northern Maine ISA's formation
was the negotiation of a Product and Service Agreement (PSA) with New Brunswick Power.
Under the PSA, New Brunswick Power will provide transmission and ancillary services, and
power services needed to operate a balancing market and to back up imports that are imported
from NEPOOL over Maine Electric's facilities. Northern Maine ISA adds that it is not at this
time economically feasible to construct transmission facilities to directly connect Northern Maine
to the rest of New England.(15)
Northern Maine ISA asserts that its authority and responsibilities are crafted to facilitate
the effective execution of two primary functions: (1) the impartial administration of the
reservation, scheduling and dispatch of the Northern Maine transmission system; and (2) the
administration of the Northern Maine market, including the operation of the markets for energy,
ancillary services and related services.(16) Northern Maine ISA also proposes to be an RTG.
Northern Maine ISA requests that the rates, terms and conditions of the arrangements set
forth in its filing be permitted to become effective on March 1, 2000. Northern Maine ISA also
requests waiver of the advance notice requirement of section 35.3(a) of the Commission's
regulations, 18 C.F.R. section 35.3(a) (1999), in order to permit Northern Maine ISA to make
this filing more than 120 days prior to the requested effective date. Northern Maine ISA submits
that good cause exists for the requested waiver because it is essential to the market participants
that this filing be accepted by the Commission as soon as possible in order to permit them to
proceed with the additional investments, acquisitions and technical steps necessary to have the
new market fully operational by March 1, 2000, as mandated by the Maine legislature.
Notice of Northern Maine ISA's filing was published in the Federal Register, 64 Fed.
Reg. 49,005 (1999), with comments, protests and interventions due on or before September 14,
1999. Dynegy Power Marketing, Inc. (Dynegy) and Maine Public Service filed timely motions to
intervene, raising no substantive issues. The Maine Public Advocate filed an untimely motion to
intervene on September 24, 1999.
II. Discussion
A. Procedural Matters
Under Rule 214 of the Commission's Rules of Practice and Procedure, 18 C.F.R. section
385.214 (1999), the timely, unopposed motions to intervene of Dynegy and Maine Public Service
serve to make them parties to this proceeding.
Docket No. ER99-4225-000 -4-
We find that good cause exists to grant the untimely, unopposed motion to intervene filed
by Maine Public Advocate, given its interest in this proceeding and the absence of any undue
prejudice or delay.
B. Northern Maine ISA's Filing
1. Relationship to Other Regional Entities
According to Northern Maine ISA, the ISA form as embodied in the ISA Tariff is the
most appropriate means, at this time, of ensuring an independent and competitive wholesale and
retail market in Northern Maine.(17) Northern Maine has a small (130 MW), widely-dispersed load,
and the electric system in Northern Maine is not directly interconnected with the NEPOOL grid.
Northern Maine ISA states that the absence of such a direct electrical interconnection, and the
attendant complexity and cost of alternative arrangements, have, to date, made participation in
NEPOOL or ISO New England infeasible. It also explains that the cost of new transmission
facilities to effect such an interconnection cannot, at present, be justified given the load in
Northern Maine.
Northern Maine ISA asserts that the costs associated with the establishment and operation
of an ISO (establishment of a separate control area, dispatch center and other necessary
institutional changes) are equally prohibitive. While Northern Maine ISA will perform some of
the functions that the Commission expects to be performed by an ISO, Northern Maine ISA will
not take operational control of transmission facilities.
Northern Maine ISA adds that the establishment of the Northern Maine ISA is not
intended to preclude the participation of the Northern Maine market and Northern Maine
participants in a broader regional transmission organization (RTO) when and if it becomes
feasible to do so. Northern Maine ISA further states that the ISA Tariff allows the Northern
Maine ISA to be modified or terminated in light of such future regional developments.(18)
Northern Maine ISA notes that the relative isolation and modest number and size of the Northern
Maine ISA participants, in fact, provide strong incentives for them to facilitate a transition to a
larger regional organization, should one develop.
2. Control of the ISA
Northern Maine ISA is a non-profit corporation whose employees may not have any
financial interest in the economic performance of any market participant. Any entity that is a
transmission user or market participant may become a member of Northern Maine ISA.
Northern Maine ISA will be governed by a seven member Board of Directors (Board), all of
Docket No. ER99-4225-000 -5-
which shall service concurrent terms and each of which shall represent one of the following
classes of entities: (1) Maine Public Service, (2) EMEC, (3) Houlton and Van Buren; (4) large
retail customers (500 kW or more) located in Northern Maine; (5) Maine Public Advocate, on
behalf of all other electric customers located in Northern Maine; (6) generators located in
Northern Maine; and (7) CEPs located in Northern Maine, except that no generator may qualify
for membership in this class. An eighth, non-voting director will be named by New Brunswick
Power. Each vote will be equally weighted. At all meetings of the Board, four Directors then in
office shall constitute a quorum for the transaction of business. A vote of no less than four
Directors at a meeting at which a quorum is present shall constitute an act of the Board. The
Board will elect a Chairman, Vice Chairman, President, Treasurer and Clerk. All Board
meetings will be open to the public except for executive session proceedings, which will only
take place when the Board considers personnel matters, legal proceedings and confidential
information from a Northern Maine ISA member provided under the ISA Tariff.
3. Duties of the ISA
In general, Northern Maine ISA's duties are governed by the ISA Tariff and may be
amended only by the Board. Northern Maine ISA states that it is obligated, consistent with the
ISA Tariff, to develop, interpret and enforce market rules and operating procedures covering all
financial and technical aspects, respectively, of the Northern Maine market. Such market rules
and operating procedures, which must be implemented prior to the effective date of the ISA
Tariff, will implement the mechanics of the daily operation of the Northern Maine market.
According to the Northern Maine ISA, the market rules and operating procedures must cover
such subjects as reservations, scheduling, dispatch, calculation of available transmission
capacity, settlement and billing, demand forecasts, outage coordination and loss administration.
While some of the market rules have been tendered in this filing, other market rules, including
the enforcement mechanism, will be filed with the Commission at a later date.(19) Northern Maine
ISA may revise the market rules only after all members have had ten days to comment, unless the
ISA determines that an immediate change is required to avoid adverse effect to the reliability,
effectiveness or security of the Northern Maine market.
Northern Maine ISA states that it will administer the reservation, scheduling and dispatch
of the Northern Maine transmission system through its administration of the Transmission Owner
(TO) tariffs.(20) Under this arrangement, the TOs will cede the
Docket No. ER99-4225-000 -6-
right to schedule and reserve the use of their transmission facilities to the Northern Maine ISA.
Northern Maine ISA asserts that it will not take operational control of the Northern Maine
transmission system. Because it will not operate a separate control and dispatch center, the
transmission system operators (TSOs)(21) will continue to be responsible for the safety and short-term reliability of the transmission system. Northern Maine ISA, however, will require that each
TSO comply with appropriate standards for the maintenance of the short-term reliability of the
transmission system that are consistent with the applicable standards set by the North American
Electric Reliability Council (NERC) and the Northeast Power Coordinating Council (NPCC).
Northern Maine ISA states that the initial market structure will consist of bilateral
transactions between and among wholesale sellers and purchasers, and between retail sellers and
customers. Any necessary scheduling adjustments and reconciliations will be accomplished by
the Northern Maine ISA through the use of Balancing Energy and Ancillary Services.
Northern Maine asserts that it will have the authority to create an energy market,
including the establishment of an hourly pricing mechanism, or to propose separate markets for
other products or services, when, in the Northern Maine ISA's judgment, market conditions so
warrant.(22) Northern Maine ISA states that any such energy or other product or services markets
will not be implemented prior to the receipt of such Commission approvals as are necessary.
Northern Maine ISA states that it also has the authority to independently assess the
competitiveness and efficiency of the Northern Maine market and that it shall convey its findings
to all ISA Members.(23) Northern Maine ISA may assess the transmission system and develop
plans for further development, expansion and improvement.(24) Northern Maine ISA's authority
includes its ability to suspend the Northern Maine market if it determines that equipment failure
or other physical occurrence will prevent the Northern Maine market from functioning in a
reasonable
Docket No. ER99-4225-000 -7-
manner as designed, or would impair the reliable operation of the transmission system.(25)
4. Rates and Terms and Conditions of Service Under the ISA Tariff
Northern Maine ISA will charge rates for two kinds of services: (1) Northern Maine
ISA's administration and monitoring services; and (2) those services which the Northern Maine
ISA purchases and resells to Northern Maine market participants. All operating expenses, capital
expenses and extraordinary expenses necessary for the Northern Maine ISA to carry out its
functions under the ISA Tariff will be recovered through a monthly charge to be allocated
among: (1) all retail customers in that month; (2) generators that transmit any energy or capacity
within, through or out of the Northern Maine market in that month (not including energy
delivered to CEPs at a generating unit); and (3) CEPs for those transactions which require the
transmission of capacity or energy within, through or out of the Northern Maine market in that
month.
The costs associated with the development and implementation of the Northern Maine
ISA have, to date, been borne by Maine Public Service, EMEC, Houlton and Van Buren. These
costs include the costs of consulting and legal representation, and technical start-up costs. These
costs ultimately will be recovered from retail customers and it is currently anticipated that these
costs will be retired through the issuance of debt, amortized over a reasonable period of time, and
collected as part of Northern Maine ISA's budgeted costs.
Section 6 of the ISA Tariff states essentially that transmission rates will be determined
based on where the loads are located, i.e., rates for transmission service will be based on the
charges set forth in the tariffs of the systems (Maine Public Services' or EMEC's) the loads are
located on. However, if at least 35% of the energy requirements of the loads served on one
system are from resources located on the other system, and this occurs for six consecutive
months, the Northern Maine ISA will develop and charge a rate that is a composite of the rates
set forth in the Maine Public Service and EMEC transmission tariffs. The composite rate shall
become effective pursuant to appropriate amendments to the Maine Public Service and EMEC
transmission tariffs and the receipt of any necessary Commission approval.
Northern Maine ISA also addresses the issue of market power in its filing. Northern
Maine ISA stakeholders believe that the steps they have taken, and the Northern Maine ISA to
which they have agreed, mitigate any market power concerns. Northern Maine ISA states that
the market to be administered by the Northern Maine ISA will be substantially more competitive,
and will provide substantially greater access for competitors, than the current market.
5. Commission Response
We will accept Northern Maine ISA's filing, which establishes the Northern Maine ISA.
Docket No. ER99-4225-000 -8-
We note that, because Northern Maine ISA is not applying for status as an ISO, we have not
evaluated the filing based on the Commission's ISO principles. Instead, we have reviewed the
filing to determine whether it is reasonable under section 205 of the FPA.
The Commission finds that the proposed rates, terms and conditions for services provided
under the ISA Tariff are reasonable. Northern Maine ISA has proposed to recover the costs
incurred by the Northern Maine ISA to carry out its functions under the ISA Tariff through a
formula rate that will allocate its expenses based on the Northern Maine system load and other
transmission uses that do not involve deliveries to those loads.
The ISA Tariff provides that, at present, there will be a single rate for services that
involve more than one transmission provider's system, based on the location of the delivery
point.(26) This type of pricing has been approved by the Commission for ISO New England.(27)
The Northern Maine market, for the moment, will use bilateral agreements. We note that
some of the market rules, such as those addressing sanctions, have yet to be finalized. The
Northern Maine ISA has committed to file these separately with the Commission. We will
review them at that time.
C. Proposal for RTG Status
The Commission set forth in the RTG Policy Statement seven minimum components that
RTG agreements should contain in order to satisfy the FPA.(28) We have described the seven
components at length in previous orders,(29) and we will not repeat that discussion here. Rather,
for the purposes of this order, the seven components may be summarized as follows: (1) broad
membership and sufficient geographic area; (2) adequate consultation and coordination with state
agencies; (3) an obligation to provide transmission services for other members; (4) coordinated
transmission planning and sharing of transmission planning information; (5) fair and
Docket No. ER99-4225-000 -9-
non-discriminatory governance and decision-making procedures; (6) voluntary dispute resolution
procedures; and (7) an exit provision that specifies the obligations of a departing member.(30) The
Commission further clarified in SWRTA and WRTA that it would condition the approval of
RTGs on the RTG members offering comparable transmission service at least to other members,
through transmission tariffs.(31) We discuss below the manner in which the provisions of Northern
Maine ISA's filing comply with these requirements.
1. Broad Membership and Sufficient Geographic Area
The RTG Policy Statement states that an RTG agreement must provide for broad
membership and, at a minimum, allow any entity that is subject to, or eligible to apply for, an
order under section 211 of the FPA to be a member. An RTG should also encompass an area of
sufficient size and contiguity to enable members to provide transmission services in a reliable,
efficient and competitive manner.(32)
Northern Maine's ISA membership includes all investor-owned, cooperatively-owned,
and municipally-owned utilities, as well as generators, suppliers of energy and large retail
customers in Northern Maine. Northern Maine ISA will encompass the entire Northern Maine
market. Northern Maine ISA's membership is as broad as could be expected for a region of this
size and location. Although the Northern Maine market is not large, its geographic isolation
from the remainder of the U.S. grid makes it a candidate for RTG status. Therefore, we conclude
that the Northern Maine ISA membership eligibility provisions and the nature of the geographic
area meet the minimum requirements of the RTG Policy Statement.
2. Adequate State Consultation and Coordination
The second component of an RTG is that it should provide for adequate consultation and
coordination with relevant state regulatory, siting, and other authorities. The RTG Policy
Statement encourages RTGs to involve the states in whatever way is most effective.(33) We
conclude that the Northern Maine ISA satisfies this component. The Maine Attorney General,
the Maine Public Advocate and the Maine Commission have been actively involved in the
formation of Northern Maine ISA. Also attached as a part of the Northern Maine ISA filing is a
letter from the Maine Commission supporting the formation of Northern Maine ISA.(34) Further,
Docket No. ER99-4225-000 -10-
the Maine Public Advocate will have a seat on the Board as a representative for retail electric
customers.
3. Obligation to Provide Service
The RTG Policy Statement states that an RTG agreement should impose an affirmative
obligation on transmitting utility RTG members to provide transmission services for other
members, including enlarging facilities, on a basis consistent with FPA sections 205, 206, 211,
212 and 213.(35)
Northern Maine ISA states that it will reserve and schedule transmission service under
Maine Public Service's current open access transmission tariff and under the comparable
transmission tariff to be filed with Northern Maine ISA by EMEC.(36) On this basis, and
consistent with the commitment that the EMEC transmission tariff will be in effect by the date on
which the ISA Tariff becomes effective, we find that Northern Maine ISA meets the third RTG
component.
4. Coordinated Transmission Plan and Sharing of Transmission Planning
Information
To address the goal of efficient use, expansion and coordination of transmission on a
grid-wide basis, the RTG Policy Statement requires an RTG agreement to provide for the
development of a coordinated regional transmission plan and the sharing of transmission
planning information. The RTG Policy Statement also requires an RTG agreement to include as
much detail as possible with regard to operational planning procedures and that the planning
process be open to all members and coordinated with other RTGs.(37)
Northern Maine ISA will be responsible for coordinated transmission planning and for
the administration of tariff services in Northern Maine, and will draft and carry out an operating
plan. We find that these actions meet the minimum requirements of the RTG Policy Statement.
Docket No. ER99-4225-000 -11-
5. Fair and Non-discriminatory Governance and Decision-Making
Procedures
Another component set forth in the RTG Policy Statement is that an RTG should include
fair, non-discriminatory governance and decision-making procedures, including voting
procedures. The Commission is particularly concerned with protecting transmission-dependent
utilities. We suggested that procedures such as "super-majority" voting rules could be used to
ensure that all interests are protected.(38)
The Commission finds Northern Maine ISA's governance and decision-making
procedures, as described above, to be fair and non-discriminatory. We believe that the
membership of the Board, the ISA's quorum requirements and its voting procedures result in fair,
non-discriminatory governance and decision-making.
6. Voluntary Dispute Resolution Procedures
The Policy Statement provides that an RTG should have voluntary alternative dispute
resolution (ADR) procedures that provide a fair alternative to resorting in the first instance to the
Commission (through a section 206 complaint or section 211 request for a transmission order).
The Commission explained that ADR procedures are particularly appropriate to address technical
and reliability issues. The Commission also indicated that it will afford appropriate deference to
the outcomes of approved ADR procedures, consistent with its obligation to ensure that the
resolution is not unjust, unreasonable, or unduly discriminatory or preferential and that it is not a
result of the exercise of market power.(39)
The ISA Tariff provides that any dispute arising between a Northern Maine ISA member
and the Northern Maine ISA may be submitted to ADR.(40) The ISA Tariff includes specific
dispute resolution procedures for non-rate issues while matters involving rates are to be
submitted directly to the Commission for review. In addition, the ADR procedures do not
preclude any entity from filing a complaint with the Commission. We find that these ADR
procedures meet the Commission's requirement.
7. Exit Provisions
The RTG Policy Statement provides, as the final RTG component, that an RTG
Docket No. ER99-4225-000
agreement should include an exit provision that specifies that obligations of a departing member
to comply with its prior commitments under the agreement.(41)
Section 10 of the ISA Tariff provides the procedures that a Northern Maine ISA member
must follow should it desire to terminate its member status. Section 10 requires that the member
provide a minimum of thirty days written notice to Northern Maine ISA. Upon termination of
membership, however, to the extent they remain in service, the former member's Northern Maine
generation and transmission (G&T) facilities shall remain subject to the Northern Maine ISA
market rules and operating procedures and the Northern Maine ISA Tariff. Northern Maine ISA
explains that as a result, the exit provisions have the dual purpose of providing the Northern
Maine ISA member with the opportunity to exit the Northern Maine ISA within a reasonable
time period, while ensuring that Northern Maine ISA operations are not disrupted by the abrupt
or unreasonable withdrawal of a former member's G&T facilities.(42) We find that Northern
Maine ISA's exit provisions satisfy the final RTG component.
D. Requests for Waiver and Effective Date
We will grant waiver of the 120-day advance notice requirement to the extent needed to
allow the filing to become effective upon commencement of service. Northern Maine ISA
should inform the Commission promptly of the date when service commences.(43)
The Commission orders:
(A) Northern Maine ISA's filing is hereby accepted for filing.
(B) Northern Maine ISA's request for RTG status is hereby granted.
(C) We grant Northern Maine ISA's request for waiver of the 120-day advance notice
requirement of the Commission's regulations.
(D) Northern Maine ISA is hereby informed of the rate schedule designation in
Attachment A.
By the Commission,
/s/ David P. Boergers
(SEAL) David P. Boergers,
Secretary
Attachment A
Northern Maine Independent System Administrator, Inc.
Docket No. ER99-4225-000
Rate Schedule Designations
Designation Description
Rate Schedule FERC No. 1 Northern Maine ISA Tariff
Rate Schedule FERC No. 2 Northern Maine ISA Market Rules
Exhibit 99(z)
STATE OF MAINE Docket No. 98-577
PUBLIC UTILITIES COMMISSION
December 1, 1999
MAINE PUBLIC UTILITIES COMMISSION ORDER APPROVING
Investigation of Stranded Costs, Transmission STIPULATION
And Distribution Utility Revenue Requirements,
And Rate Design of Maine Public Service Company
WELCH, Chairman; NUGENT and DIAMOND, Commissioners
I. SUMMARY
We approve a stipulation that resolves all disputed issues in this investigation.
By the settlement, the parties agreed that Maine Public Service Company's (MPS) T&D
revenue requirement, exclusive of stranded costs, shall be approximately $16,640,000.
As part of the revenue requirement, the parties agreed that MPS's cost of equity is
10.7%, with a 51% equity ratio. The parties agreed to a "top-down" methodology for
establishing MPS's core class rate design. The parties also agreed to the proper design
of the T&D version of Rate B, MPS's standby rate.
II. INTRODUCTION AND PROCEDURAL HISTORY
In this case, the Commission implements the legislative directive in the Electric
Restructuring Act (35-A M.R.S.A. sections 3201-3217) to establish Maine Public
Service Company's rates for the start of retail choice on March 1, 2000. On that date,
electric generation retail service becomes subject to competition rather than rate
regulation. The delivery of electricity will remain regulated as a utility service.
The Restructuring Act requires each electric utility to divest generation-related
assets and businesses. The Commission must conduct adjudicatory proceedings to
determine for each utility the generation costs stranded by restructuring. In the same
proceeding, the Commission must determine the revenue requirement for the remaining
transmission and distribution (T&D) utility and the stranded cost charges that will be
collected through the T&D rates. 35-A M.R.S.A. section 3208(8). These adjudicatory
proceedings must be concluded by December 1, 1999. Id.
The Commission must also design rates to recover the revenue requirement for
T&D costs, stranded costs, and any other costs required by the Act to be recovered
through T&D rates. The Act also requires the Commission to design rates for backup or
standby service. These rate design adjudicatory proceedings must be completed by
December 1, 1999. 35-A M.R.S.A. section 3209.
This investigation was initiated by the Commission on August 5, 1998 in order to
fulfill our obligation to determine MPS's T&D and stranded costs revenue requirement
Order - 2 - Docket No. 98-577
and T&D rate design. In response to our Notice of Investigation, MPS filed its direct
case on October 15, 1999. Timely petitions to intervene were granted from the Office
of the Public Advocate (OPA), Wheelabrator-Sherman Energy Company, Bangor
Hydro-Electric Company (BHE), Central Maine Power Company (CMP), and Houlton
Water Company (HWC).1 The late-filed petitions to intervene on behalf of Pinkham
Lumber Company and McCain Foods, Inc. were also granted.
In its direct case filing, MPS determined its T&D revenue requirement (not
including stranded costs) to be $19,337,800. MPS also estimated its stranded costs
revenue requirement by assuming its generation asset sale to WPS-PDI was completed
and by estimating the revenue for selling the output from its QF contract with
Wheelabrator-Sherman.
In response to MPS's direct case, the OPA filed direct testimony proposing
revenue requirement adjustments, including different cost allocations between T&D and
generation functions and a lower cost of capital. The OPA also filed testimony on rate
design. Wheelabrator Sherman filed direct testimony on standby rate design.
After the Company filed its rebuttal case in February, 1999, the Advisors
presented a Bench Analysis to the parties on June 21, 1999. The Advisors proposed
additional ratemaking adjustments, including the addition of a productivity offset as part
of the attrition adjustment. The Advisors also proposed a cost of equity for MPS of
10.7%, based upon a capital structure that included 49% equity.
In its response to the Bench Analysis and surrebuttal testimony, MPS revised its
T&D revenue requirement, without stranded costs, to $17,324,000. After a series of
settlement conferences in which the advisors participated, the parties, with the
concurrence of the advisors, agreed upon the parameters of a settlement to this
investigation. The parties then reduced their oral agreement from the settlement
conferences into a written stipulation that was filed with the Commission on October 14,
1999. All parties either joined the stipulation, or at least did not oppose the stipulation,
except for McCain. After McCain raised issues concerning the design of a T&D standby
rate, additional settlement conferences were held and an amendment to the stipulation
was filed on November 18, 1999. After the amendment and some further discussion
concerning the interpretation of the present Rate B, counsel for McCain indicated to the
Examiner that McCain does not object to the stipulation.
III. DESCRIPTION OF THE STIPULATION
The parties agree that MPS's T&D revenue requirement, excluding stranded
costs, shall be $16,640,000. This T&D revenue requirement is based upon an after-tax,
weighted cost of capital of 9.65%, which includes a cost of equity of 10.7% and a 51%
equity ratio. The parties also agree that the T&D revenue requirement should be
1 The petitions for HWC, BHE and CMP were granted on the understanding that
each was merely monitoring the case.
Order - 3 - Docket No. 98-577
adjusted in an update phase before March 1, 2000. If, before the update is complete,
the State Planning Office determines that MPS should increase its DSM expenses
beyond the minimum established by statute, that amount should be included in the
update. If the DSM spending level is changed after the update phase, MPS shall defer
the effect of the increased spending. The T&D revenue requirement should also be
adjusted in the update phase for MPS's adjustments to its Flexible Pricing Plan special
contracts necessitated by electric restructuring.
The parties agree that T&D rate design should be accomplished using a "top-down" methodology. The top-down methodology means that generation costs will be
removed from current rates using standard offer prices, although such prices may be
adjusted by the Commission for voltage levels, line losses or other known data.
The parties clarified their agreement as to the proper design of the T&D standby
rate in the November 18 amendment. The parties agree that, in accord with the
principles established in CMP's T&D rate investigation (Docket No. 97-580), the proper
T&D standby rate for MPS should be current Rate B, adjusted to remove generation.
The parties agree the workpapers attached to the amendment describe the manner to
remove generation costs. By the amendment, the parties also agree that the limitation
in the current Rate B to facilities of less than 2MW and a system total limit of 10MW,
should be removed in the T&D-only environment.
The parties acknowledge that MPS's stranded costs revenue requirement cannot
be calculated until an update phase, after the Wheelabrator-Sherman power output has
been auctioned for the first two years of restructuring and the Commission chooses the
amortization of the available value from MPS's generation asset sale. The parties do
agree, however on some stranded costs recovery principles. The parties agree that
MPS's stranded costs, as described in the stipulation, are legitimate, verifiable and
unmitigable, and therefore recoverable under the Restructuring Act. The parties agree
that MPS can offset available value to recognize the deferred rate increase of 3.66%,
authorized in April, 1999 in Docket 98-865. The parties agree that recovery of MPS's
regulatory assets associated with its Seabrook investment should not be accelerated,
but that MPS will be entitled to offset a portion of its unrecovered Seabrook investment
by an amount of MPS's available value, to be determined by the Commission in the
update phase, and which in no event will be greater than 50% of the available value.
The parties agree that stranded costs associated with Maine Yankee will not include
costs related to payments to Texas pursuant to the Low Level Waste Compact nor
payments to replenish Maine's Spent Fuel Trust Fund. The parties agree, however, that
MPS may defer any payments that MPS must make to Maine Yankee for either of these
expenses in the stranded costs rate effective period. MPS also agrees to be bound by
the final ruling in CMP's request for an IRS letter ruling with respect to the normalization
requirement for the Investment Tax Credits (ITCs) and Excess Deferred Income Taxes
(EDITs) associated with the generation assets sold as part of restructuring.
The Advisors have participated in the settlement conferences, and recommend
that the Commission approve the Stipulation.
Order - 4 - Docket No. 98-577
IV. DECISION
We have reviewed the stipulation and find that it represents a just and
reasonable resolution of the issues raised in this phase of our investigation.
Accordingly, we approve the stipulation. The stipulation, therefore, meets one of the
criteria we have set for approving stipulations: that the result is reasonable and not
contrary to any legislative mandate. The other two criteria are also met. The process
that led to the stipulation was fair to all parties; the settlement occurred after all parties
had opportunity to develop their cases, and the negotiation took place at a settlement
conference initiated by the Advisors to which all parties were invited. Lastly the parties
joining the stipulation represent a sufficiently broad spectrum of interests such that the
Commission can be sure there is no appearance or reality of disenfranchisement. Our
notice of investigation was well publicized, all petitions to intervene were granted, and
all intervenors join or at least do not oppose the stipulation.
The parties have agreed to a cost of capital and capital structure almost identical
to that recommended by the Advisors in the Bench Analysis. Although the parties have
simply agreed to a bottom-line, T&D-only revenue requirement, from reviewing the
testimony and Bench Analysis, we can approximate that the parties have implicitly
adopted somewhat more than half of the adjustments proposed by the intervenors and
the Bench, even after adjusting for the Bench's recommended cost of capital. As the
total value of the disputed issues was not large, less than $500,000 after adjusting for
the Advisors' cost of capital, our analysis shows that the compromise reached on the
T&D revenue requirement is reasonable.
The stipulation's rate design provisions follow the principles we adopted in
CMP's T&D rate investigation, Docket 97-580. We find the rate design provisions to be
reasonable. The removal of the limitations in the current standby rate (Rate B), while
arguably beyond a strict interpretation of Docket 97-580's "no losers" principle, appears
to be a reasonable compromise by MPS in light of the deregulation of generation. We
accept the compromise reached by the parties.
We also find the stranded costs principles within the stipulation to be reasonable.
The agreement that MPS's stranded costs are legitimate, verifiable and unmitigable is
consistent with the evidence in this case and our decision authorizing MPS's sale of
generation assets, Docket 98-584. The treatment of stranded costs associated with
Seabrook, Maine Yankee, EDITs and ITCs, and the deferred 3.66%, Docket 98-865
rate increase, is reasonable and consistent with our decision in the T&D rate
investigations for CMP (Docket 97-580) and BHE (Docket 97-596).
Order - 5 - Docket No. 98-577
Accordingly, we
O R D E R
That the stipulation and amendment to the stipulation, attached to this Order and
incorporated by reference into this Order, is approved.
Dated at Augusta, Maine, this 1st day of December, 1999.
BY ORDER OF THE COMMISSION
_______________________________
Dennis L. Keschl
Administrative Director
COMMISSIONERS VOTING FOR: Welch
Nugent
Diamond
Order - 6 - Docket No. 98-577
State of Maine Docket No. 98-577
Public Utilities Commission
October 14, 1999
Public Utilities Commission Re: Stipulation
Investigation of Stranded Costs,
Transmission and Distribution
Utility Revenue Requirements,
And Rate Design of Maine Public
Service Company
_____ The undersigned, being parties to this proceeding, agree as follows:
1. Purpose This Stipulation is intended to resolve all of the issues set forth in the
Commission's August 3, 1998, Notice of Investigation in this docket regarding
the revenue requirement and rate design of Maine Public Service Company's
(MPS) Transmission and Distribution Company (the T & D utility). The
Stipulation also sets forth general areas of agreement governing the recovery of
MPS's stranded costs. As evidenced by their signatures on this Stipulation, the
undersigned agree that the terms set forth herein are reasonable and should be
adopted by the Commission.
A. Revenue Requirement
______2. Annual T & D Revenues Effective March 1, 2000, the annual jurisdictional
revenue requirement (exclusive of any stranded investment recovery) of MPS's T
& D utility shall be $16,640,000, subject to paragraph 4 below.
3. Cost of Capital For the purpose of determining the annual revenue requirement set
forth in paragraph 2 above, the parties agree to a weighted, after-tax cost of capital
of 9.65% (13.27% on a pre-tax basis), derived as follows:
Cost of Capital Capital Component
Equity 10.7% 51%
Long-Term Debt 8.6% 45%
Short-Term Debt 8.0 % 4%
100%
Order - 7 - Docket No. 98-577
4. Revenue Requirement Items Subject to Future Adjustment
(a) Chapter 380 Expenses. Pursuant to 35-A MRSA 32ll, MPS will, prior to
March 1, 2000, be obligated to fund certain conservation programs as
determined by the State Planning Office (SPO) pursuant to 5 MRSA 3305-B. The revenue requirement set forth in paragraph 2 above reflects MPS's
funding of such programs at the stipulated amount of $157,674. Should
the SPO require MPS to fund conservation programs in an amount that
varies from this $157,674 during the rate-effective period then the parties
agree that MPS shall be permitted to recover any variation as follows:
1. If the amount of the variation is announced prior to March 1, 2000,
MPS may collect that variation through the rates that shall become
effective March 1, 2000, by adding that amount to the revenue
requirement set forth in paragraph 2.
2. If the amount of the variation is announced after March 1, 2000,
MPS shall defer the variation on its books of account and shall be
entitled to recover the variation in rates established in its next
general rate case after March 1, 2000.
(b) Flexible Pricing Adjustment. The revenue requirement set forth in
paragraph 2, includes $473,526 to reflect revenues lost due to MPS's
special contracts and discounted rate classes pursuant to its Flexible
Pricing Plan authorized by this Commission in Docket 95-052, and is in
accordance with the rate making treatment recommended by the June 21,
1999, Bench Analysis in this docket. The calculation of this lost revenue is
set forth in Exhibit BMB-1, page 3 of 3 to the August 19, 1999,
Supplemental Surrebuttal Testimony of Brent Boyles. The parties agree
that the method set forth in BMB-1 is a reasonable method for calculating
the revenue requirement resulting from MPS's Flexible Pricing Plan but
further agree that the amounts shown in this Exhibit must be recalculated
in light of the Rate Design agreements in Subsection B below. The parties
therefore agree that MPS shall adjust the revenue requirement set forth in
paragraph 2 to reflect this recalculation of the Flexible Pricing adjustment
using the method set forth in BMB-1. MPS shall complete the
recalculation by November 15, 1999.
B. Rate Design
The parties agree that beginning March 1, 2000, MPS T&D utility rate design shall be based on
the following:
Order - 8 - Docket No. 98-577
5. Top-Down Methodology. In order to reduce customer confusion and adverse bill
impacts, the parties agree to use a "top-down" methodology as the basis for
establishing MPS's core class rate design. This methodology shall be
implemented (on a rate-year basis) in the following way:
(a) The total revenue requirement to be recovered from core customers ("Core
Revenue Requirement") will be equal to the Company 's total T&D
revenue requirement plus the Company's total stranded cost revenue
requirement minus the Adjusted Rate-Year Non-Core T&D Revenues.
(b) The revenue requirement to be recovered from each class will be
determined as follows:
RRC = Core Revenue Requirement
Class RB = Revenue from core customers in class at current bundled rates
Class RSO = For each class, the Core Rate-Year billing units multiplied by
the applicable Standard Offer price. The Standard Offer prices may be
adjusted using rate class voltage levels, line losses or other known class
data as the Commission determines proper.
For each class, the Unbundled Revenue Requirement =
ClassRB - {[yClassRB
- - RRC] x [(ClassRSO)/yClassRSO]}
(c) Within each class, the rate elements will be determined as follows:
ClassRRC = Unbundled Core Revenue Requirement for that class
REB = Bundled Rate Element
RESO = Standard Offer Rate Element
BURE = Billing Units for each rate element in that class
For each rate element, the Unbundled rate element =
REB - {(ClassRB - ClassRRC) x [(RESO x BURE) / y(RESO x
BURE)]/BURE}
Where yRESO x BURE =
the sum, for that class, of each rate element
multiplied by its applicable billing units.
Order - 9 - Docket No. 98-577
(d) The Adjusted Rate-Year Non-Core T&D Revenues will be estimated to be
$7,317,000 (as calculated in Appendix A). This value is subject to
modification, based on differences between the assumptions in Appendix
A and the special rate contracts actually approved by the Commission
between now and February, 2000.
6. Stand-By Rates. All stand-by service, including that provided to generating
stations and customers with self-generation, after March 1, 2000, shall, until
otherwise ordered by the Commission, be offered by MPS through a rate that
consists of MPS's current bundled Rate B from which have been subtracted all
generation costs according to the method set forth in paragraph 5 above.
7. Demand Ratchet. MPS will eliminate all demand ratchets from its rates. Revenue
associated with the demand ratchet will be collected through the demand charge.
8. Residential Rate A. MPS currently has an inverted block structure for its
Residential Rate A, which it has proposed to eliminate and replace with a flat rate.
The parties agree to defer consideration of this issue until such time as the
Standard Offer prices for MPS's service territory and the results of the Chapter
307 auction are announced and MPS's design for core rates has been determined
under paragraph 5 above. At that time the parties shall reevaluate the elimination
or reduction of MPS's inverted block Rate A subject to the condition that no Rate
A customer will see other than a minimal monthly bill increase as a result of the
elimination or reduction of the inverted block structure.
C. Stranded Investment
The parties agree that the precise level of stranded cost recovery cannot be determined
until after the results of the Chapter 307 auction of the output of the Wheelabrator-Sherman
contract and all costs associated with the sale of the MPS's generating assets are known. In
addition, MPS's auditors must complete their examination of the tax calculations and deferred
gain in the generation asset sale. The parties do, however, agree on the following principles
regarding MPS's stranded cost calculation and further agree those principles shall be reflected in
the calculation of the Company's ultimate stranded cost recovery.
9. Further Proceeding. This Docket shall be held open in order to permit the
determination of the exact level of MPS's stranded cost recovery once the terms of
MPS's sale of its entitlement to the output of Wheelabrator-Sherman under
Chapter 307 are known. This determination should be made before February 1,
2000. The stranded investment then calculated shall use a rate effective period of
two years.
10. Stranded Investment. MPS's stranded costs consist of: (i) the above-market value
of the Wheelabrator-Sherman Power Contract; (ii) the Company's remaining
unamortized investment in the Seabrook Nuclear Project; (iii) costs incurred for
the buy-down of the Wheelabrator-Sherman Contract; (iv) Deferred fuel costs
Order - 10 - Docket No. 98-577
from the Wheelabrator-Sherman Contract and Maine Yankee as permitted by the
Rate Stabilization Plan approved in Docket 95-052 are estimated and reflected in
Exhibit SLB-3, page 4 to the Surrebuttal Testimony of Messrs. LaPlante and
Brown; (v) MPS's continuing obligation for its share of operating expenses of
Maine Yankee, including its share of decommissioning, as well as its recovery of
its remaining investment in Maine Yankee and (vi) other regulatory assets as
allowed by this Commission in other proceedings. The parties agree that those
stranded investments are legitimate, verifiable and unmitigable as of the date of
this Stipulation. Recoverable stranded investment will be determined in the
proceeding described in paragraph 9.
11. Seabrook. MPS shall continue to amortize its unrecovered investment in the
Seabrook Nuclear Unit over the period authorized by the Commission in Docket
Nos. 84-80 and 84-113. Contemporaneously with the beginning of stranded
investment recovery on March 1, 2000, MPS shall be entitled to offset a portion
of its unrecovered Seabrook stranded investment by an amount of MPS's available
value, which amount shall be determined in the proceeding referred to in
paragraph 9, and which shall not exceed 50% of the available value.
12. Maine Yankee. The parties agree that Exhibit SLB-4 to the Surrebuttal Testimony
of Messrs. LaPlante and Brown fully and finally reflects all adjustments required
to be made to Maine Yankee stranded investment on account of any issue
(whether the subject of an extant settlement or otherwise) of prudency or
reasonableness with regard to the ownership, operation, management or any other
matter related to Maine Yankee (including any settlement between Maine Yankee
and any consumer-owned utilities) and that no further adjustment to the totals
shown on that Exhibit shall be made on account of such issues, except for
adjustments required by orders or settlements in being as of the date of this
Stipulation. The parties agree that the Maine Yankee stranded investment
calculation shown on SLB-4 must be adjusted by removing any costs of the ISFSI
collections and Texas low level waste compact payments that have been included
in that calculation. If such costs are charged to MPS after March 1, 2000, MPS
may defer those costs and shall be entitled to seek their recovery in rates in the
next general rate case.
13. Docket 98-865. MPS shall offset available value to reflect the recognition of a
foregone 3.66% rate increase as authorized by the Commission in Docket 98-865.
14. Certain Taxes As An Offset To Stranded Investment. MPS's sale of certain
generating assets to WPS-PDI has raised an issue concerning MPS's unamortized
Investment Tax Credits (ITCs) and Excess Deferred Income Taxes (EDITs) that
have been recorded with respect to those assets. MPS has stated that recognizing
ITCs and EDITs as regulatory assets to offset stranded investment would violate
the normalization requirements of the Internal Revenue Code, although the IRS
has not yet issued a definitive opinion in this matter in the context of electric
restructuring and the mandated sale of generating assets. This same issue was
Order - 11 - Docket No. 98-577
addressed in Docket 97-580 in which the Commission ordered CMP to obtain
from the IRS a private letter ruling on this matter. MPS has reviewed CMP's
request for a private letter ruling and agrees to be bound by any final definitive
ruling on this issue.
15. Stranded Investment Rate Design. MPS shall allocate its recoverable stranded
investment among customer classes on a "top-down" approach, in the manner set
forth in paragraph 5 (b) and (c).
- Docket 98-138 Cap. In Docket 98-138, the Commission stated the need to create
an ROE margin that could be added to an index of water utilities to determine a
maximum future cost of equity for MPS should a representative peer group of
electric utilities be unavailable. The parties agree that this margin should be 185
basis points above the index of proper water utilities.
17. Stipulation Not Precedential. The making of this Stipulation by the parties shall
not constitute precedent as to any matter of law or fact, nor, except as provided
herein, shall it prevent any party from making any contention or exercising any
right, including rights of appeal, in any other Commission proceeding or
investigation or any other trial or action.
18. Construction of Stipulation. The parties agree that this Stipulation shall be
considered by the Commission as an integrated solution to the issues addressed
herein and shall be null and void and shall not bind the parties if the Commission
does not accept it without modification.
In Witness Whereof, the Parties have caused this Stipulation to be signed by their
respective attorneys.
October 14, 1999 MAINE PUBLIC SERVICE COMPANY
By
Stephen A. Johnson, General Counsel.
Order - 12 - Docket No. 98-577
October , 1999 OFFICE OF THE PUBLIC ADVOCATE
By
____________________________ Stephen G. Ward. Public Advocate
October , 1999 WHEELABRATOR-SHERMAN ENERGY
COMPANY
By
____________________________ Patrick J. Scully
October , 1999 MCCAIN FOODS
By
____________________________
Order - 13 - Docket No. 98-577
State of Maine ) Docket No. 98-577
Public Utilities Commission )
)
Public Utilities Commission ) November 18, 1999
Re: Investigation of Stranded Costs, )
Transmission and Distribution Utility ) First Amendment to Stipulation
Revenue Requirements and Rate Design )
of Maine Public Service Company )
Maine Public Service Company, the Office of the Public Advocate and Wheelabrator-Sherman Energy Company hereby amend the October 14, 1999 Stipulation in the above, to which
they are the sole signatories, as follows:
1. Under Section B(5) add a new final paragraph: "Notwithstanding any of the
foregoing, the parties intend to remove all production costs from all energy and
demand components of MPS's core rates, including Rate B, as illustrated by MPS in
its response to HE-Oral-1, which is attached hereto and made a part hereof."
2. Under B(6), add a new final sentence: "In addition, MPS, for rates effective under
this Stipulation, shall eliminate both the 2 MW per facility and 10 MW total system
limitations contained in the current Rate B."
3. Except as expressly amended above, the Stipulation remains in full force and effect.
4. The Office of the Public Advocate and Wheelabrator-Sherman Energy Company
have orally agreed to this amendment and have authorized MPS to state that
agreement.
Dated: November 18, 1999 MAINE PUBLIC SERVICE COMPANY
By
_________________________________________ Stephen A. Johnson
Its Vice President
Exhibit 99(aa)
STATE OF MAINE
PUBLIC UTILITIES COMMISSION Docket No. 99-111
December 3, 1999
MAINE PUBLIC UTILITIES COMMISSION ORDER DESIGNATING
Standard Offer Bidding Procedure STANDARD OFFER
PROVIDER AND REJECTING
CERTAIN BIDS (CMP)
WELCH, Chairman; NUGENT and DIAMOND, Commissioners
I. SUMMARY
In this Order we: (1) designate Energy Atlantic (EA) as the standard offer
provider for residential/small non-residential customers in the Central Maine Power
Company (CMP) service territory for a 2-year period (March 1, 2000 - February 28,
2002) at a standard offer price of $0.04089/kWh; (2) reject the bids received to provide
standard offer service to CMP's medium and large non-residential customers, and (3)
set the standard offer price for CMP's medium and large non-residential customers at
$0.04089/kWh.
II. BACKGROUND
During its 1997 session, the Legislature enacted comprehensive legislation to
restructure Maine's electric utility industry. P.L. 1997, ch. 316 (codified at 35-A M.R.S.A.
sections 3201-3217). That legislation provides that all electricity consumers in Maine
will have the right to purchase generation services from competitive electricity providers
beginning March 1, 2000. The Legislature recognized that, at least initially, not all
consumers would want or be able to obtain generation services from the competitive
market. Accordingly, the Legislature required standard offer service to be available for
all electricity consumers who do not otherwise obtain service from the
competitive market. 35-A M.R.S.A. section 3212. The Legislature decided that the
providers of standard offer service would be chosen by the Commission through a bid
process and directed the Commission to promulgate rules to govern the bid and
selection process.
Through Orders issued April 22, 1998 and June 29, 1999, the Commission
adopted Chapter 301 of its rules. Chapter 301 governs standard offer service and the
provider selection process. Docket Nos. 97-739, 98-576. Pursuant to Chapter 301,
there is a separate bid process for each utility service territory. Within each territory,
bidders may bid on three separate customer classes (residential and small non-residential, medium non-residential, and large non-residential). Bidders are required to
commit to a fixed price for a 12-month period and must post security to ensure they are
financially capable of providing standard offer service at their stated price.
Order - 2 - Docket No. 99-111
Consistent with the provisions in Chapter 301, on August 2, 1999, the
Commission issued three RFBs: one each to provide standard offer service to
customers of CMP, Bangor Hydro-Electric Company (BHE), and Maine Public Service
Company (MPS). On October 1, 1999 the Commission received proposals in response
to the RFBs. The proposals were reviewed by the Commission, its staff and a
consultant retained to assist with the process.
On October 25, 1999, the Commission issued an Order that rejected the bids
received for the service territories of CMP and BHE, terminated that RFB process, and
initiated a new selection process for standard offer providers for CMP and BHE
customers. On October 26, 1999, a letter was sent to all bidders in the initial RFB
process and to all bidders in the concurrent utility RFB processes for the sale of each
utility's generation entitlements pursuant to Chapter 307 of the Commission's rules.
The October 26 letter explained the new bidding and selection process and invited the
bidders' participation.
On November 8, 1999, the Commission received proposals in response to the
new solicitation. The proposals were reviewed by the Commission, its staff and
consultant. The results of this review for the CMP 1 service territory are described
below.2
III. DECISION
A. Residential/Small Non-Residential Class
We designate Energy Atlantic (EA) as the standard offer provider for the
entire residential/small non-residential standard offer class in CMP's service territory.
EA's bid price will result in the lowest cost standard offer service for this class from
among the bids received. Acceptance of additional, higher bids for a portion of this
class to further the objective of obtaining at least three standard offer providers for the
CMP service territory would violate the rate impact test contained in section 8(C)(4) of
Chapter 301. EA's bid price and, thus, the resulting price for standard offer service in
this class is $0.04089/kWh.
EA submitted its $0.04089/kWh bid price for either one or two years. We
accept the 2-year proposal. Based on the results of our standard offer solicitations and
our observations of the New England power market, $0.04089/kWh appears to be an
attractive retail price. By accepting EA's 2-year proposal, we remove the risk that
market conditions could cause the second-year standard offer price for the CMP
residential/small non-residential class to be substantially higher. If the opposite
condition prevails and market prices are lower, marketers can offer prices lower than
1 In a separate order issued today we determine the results for BHE.
2 Because contracts and other arrangements must still be completed, we are not at this
time releasing information about non-winning bids. We intend to do so after the
contracts and other arrangements are finalized which should occur in about two weeks.
Order - 3 - Docket No. 99-111
the standard offer price, providing consumers with the benefit of lower market costs.
Thus, in light of the uncertainty over future prices, our view is that the public interest is
best served by the certainty and stability of the 2-year bid.
Section 7 of Chapter 301 provides that the duration of the initial standard offer
period will be one year. However, section 10 of the rule allows us, where good cause
exists, to waive any requirement not required by statute, provided that the waiver is not
inconsistent with the purposes of the Chapter or restructuring statute. The purpose of
the standard offer statute and rule is to procure generation service from the market at a
reasonable price for all customers that, for whatever reasons, do not obtain service
from a competitive supplier. By accepting the 2-year competitively-procured bid price,
we ensure a reasonably priced standard offer for a second year and remove the risk of
high rates that could occur to the detriment of customers. For these reasons, we find
that good cause exists, and a waiver allowing acceptance of the 2-year bid is not
inconsistent with the purposes of the Chapter or the rule. Accordingly, we waive all
requirements of Chapter 301 necessary to accept the 2-year bid.
EA has already obtained from the Commission a license to provide
standard offer service. Consistent with our standard offer RFB, EA must execute the
standard offer contract with CMP and furnish the required financial security instrument
within two weeks of the date of this Order.
EA's standard offer proposal was made contingent upon acceptance of a
companion proposal made by Engage Energy US, L.P. (Engage)3 to purchase the
entitlements to capacity and energy from CMP's undivested generation assets and
contracts. These entitlements are concurrently in the process of being sold by CMP
pursuant to Chapter 307 of the Commission's rules.4 Engage will presumably use these
entitlements, at least in part, to supply EA with capacity and energy to provide standard
offer service. In a separate order issued today in CMP's Chapter 307 proceeding,
Docket No. 99-764, we direct CMP to execute contracts with Engage consistent with
the EA/Engage combined proposal.5
B. Medium and Large Non-Residential Standard Offer Classes
We reject the bids received for the medium and large non-residential
standard offer classes in CMP's service territory. Bids received for these classes
pursuant to the new selection process were non-conforming, and are rejected on that
basis. Pursuant to Chapter 301, section 8(D), standard offer service will be provided to
3 Engage is a joint venture of Coastal Corporation and Westcoast Energy Inc.
(both established energy companies) and is not a corporate affiliate of EA.
4 Standard offer and Chapter 307 entitlement contingent proposals were invited
pursuant to our October 25, 1999 Order and October 26, 1999 letter to bidders.
5 As described in the Docket No. 99-764 Order, the Engage bid for CMP's
Chapter 307 entitlements yields a value for the entitlements that is very close to the
highest value that would have occurred on a stand-alone basis.
Order - 4 - Docket No. 99-111
customers in these classes by CMP using power procured through the wholesale
market. We will meet with CMP at the earliest possible opportunity to discuss the
process by which it will procure power supply.
Having rejected the bids for the medium and large non-residential classes,
we must administratively set the standard offer price customers in these classes will
pay for standard offer service. Ch. 301, section 8(D)(3). We set the price at
$0.04089/kWh for both classes, which is the same as the price obtained for the CMP
residential/small non-residential class through our competitive bid process. We will re-examine the prices when CMP has procured the power supply necessary to provide the
service, or when we can make a reasonable estimate of CMP's cost for that supply. If
the standard offer prices paid by medium and large non-residential customers are
substantially lower than CMP's costs to provide standard offer service, we may increase
the standard offer price to reflect costs more closely so that large deferrals are avoided
and the prices marketers have to compete with are not artificially low. However, to
provide predictability for marketers that must compete with the standard offer price, we
will not reduce the medium or large non-residential class standard offer price for the 12-month standard offer period. To the extent the standard offer price is higher than
CMP's cost of service, the difference will be returned to consumers through future
ratemaking
adjustments.
We have chosen to administratively set the price for the medium and large non-residential classes, subject to change only as discussed above, because we believe it
is important that both customers and competitive providers know the standard offer
prices by early December. We have set the standard offer price for the medium and
large non-residential classes equal to the residential/small non-residential price, which
is a market determined price. Because of traditional cost-based factors, such as line
losses and customer load shapes, prices for medium and large non-residential
customers are typically not higher than the prices paid by residential and small non-residential customers. However, in this case, the market did not produce such prices
for the medium and large non-residential standard offer classes. Therefore, as noted
above, we will set the prices for these classes equal to the market-based price for the
residential/small non-residential class, and will re-examine the prices when the costs of
the underlying wholesale power supply are better known.
Dated at Augusta, Maine, this 3rd day of December, 1999.
BY ORDER OF THE COMMISSION
/s/ Dennis L. Keschl
Dennis L. Keschl
Administrative Director
COMMISSIONERS VOTING FOR: Welch
Nugent
Diamond
Order - 5 - Docket No. 99-111
NOTICE OF RIGHTS TO REVIEW OR APPEAL
5 M.R.S.A. section 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. section 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. section 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(ab)
STATE OF MAINE Docket No. 98-577
PUBLIC UTILITIES COMMISSION
February 17, 2000
MAINE PUBLIC UTILITIES COMMISSION ORDER APPROVING
Investigation of Stranded Costs, Transmission PHASE II STIPULATION
And Distribution Utility Revenue Requirements
And Rate Design of Maine Public Service Company
WELCH, Chairman; NUGENT and DIAMOND, Commissioners
I. SUMMARY
We hereby approve a Stipulation that resolves all issues in Phase II of this
investigation. With the resolution of the Phase II issues, we establish transmission and
distribution utility rates for Maine Public Service Company (MPS) to be effective on March 1,
2000. On that date, MPS ceases to provide generation service and becomes a transmission and
distribution utility. Ratepayers will receive generation service from the standard offer or a
competitive electricity provider. The resulting T&D rates, when combined with the applicable
standard offer rates, result in class average decreases in the following amounts compared to
current bundled rates:
Residential 8.2%
Small Commercial 3.7%
Medium Commercial & Industrial 4.6 to 4.8%
Large Commercial & Industrial 4.6 to 5.2%
The overall decrease for MPS core customers is 6.1%.
II. BACKGROUND
By Order dated December 1, 1999, in this Docket, we approved a Phase I stipulation
by which the parties agreed that MPS's T&D revenue requirement, exclusive of stranded costs,
shall be approximately $16,640,000. The Phase I stipulation also provided for a "top down"
methodology for establishing MPS's core class rate design, and the proper design of the T&D
version of Rate B, MPS's stand-by rate.
The Phase I Stipulation and Order left open the determination of MPS's stranded costs
revenue requirement. The parties did agree that the stranded costs revenue requirement should be
calculated using a rate effective period of two years beginning March 1, 2000. The
determination of stranded costs had to be deferred until after the results of the Chapter 307
auction of the output of MPS's Wheelabrator/Sherman
ORDER APPROVING - 2 - Docket No. 98-577
Qualifying Facility (QF) contract (44)
and all costs associated with the sale of MPS's generating
assets were finalized. Although the top-down principle was established in Phase I, the actual
design of T&D rates could not be accomplished in Phase I. Only after standard offer Service
rates and the stranded costs revenue requirement were known, could current bundled rates be
compared with the post March 1, 2000 combination of standard offer rates and T&D rates
(including stranded costs). T&D rates would not be established in a vacuum, but would be
established only after post-electric restructuring rates were compared with current bundled rates.
Accordingly, a Phase II of this case was necessary.
In its Phase II filing, MPS proposed to apply 50% of the available value from its
generation asset sale to offset its unrecovered Seabrook investment, and to amortize the
remaining available value over four years. When combined with the forecasted revenue to be
received from the sales of the output of MPS's QF contract, this amortization would result in an
approximately levelized annual stranded cost revenue requirement of $13.4 million through the
year 2009.(45) By 2010, MPS proposed to recover the last of its regulatory asset referred to as
"deferred fuel", meaning deferred expenses associated with the Wheelabrator/Sherman buyout,
and Maine Yankee expenses during the rate plan period. The Seabrook regulatory asset is the
only other stranded cost to be recovered after 2009. The 30-year amortization period of
Seabrook will end in 2016.
When combined with the standard offer rates for its service territory, MPS's Phase II-proposed T&D rates resulted in a 3.9% rate decrease on average over current bundled MPS rates.
Because MPS proposed to eliminate the inverted block structure of its residential rate, the 3.9%
class average decrease resulted in approximately a 4% rate increase for residential customers that
use between 100 and 400 kWh per month and a 9% decrease to residential customers with usage
of 1,000 kWh per month.
III. DESCRIPTION OF THE STIPULATION
Only the Office of the Public Advocate (OPA) and MPS have been active parties in
Phase II of this proceeding. The OPA and MPS stipulate that the annual revenue requirement of
MPS's stranded costs for the period March 1, 2000 through February 28, 2002 shall be
$12,503,000. The OPA and MPS also stipulate that MPS shall be allowed to offset its
unrecovered investment in the Seabrook Nuclear Power Plant
ORDER APPROVING - 3 - Docket No. 98-577
by an amount equal to 35% of the available value from MPS's generation asset sale, which offset
results in $15,100,000 of unamortized Seabrook investment.(46)
The OPA and MPS agree that MPS should eliminate the inclining block for the
Residential Rate A and to replace it with a flat usage rate. However, contrary to MPS's filing,
the OPA and MPS agree to eliminate Rate A's inclining block structure without increasing the
total electric monthly bill of any residential customer. MPS would accomplish this result by
reducing the annual revenue requirement of Residential Rate A customers in the amount of
$915,000. The revenue requirement reduction is achieved by a reduction in the available value.
Thus, the annual revenue requirement associated with stranded costs is reduced from $13.4
million to approximately $12.5 million.
The parties also agree that the implementation of the top down method as described in
the Phase I Order and Stipulation results in an anomaly in MPS's time-of-use rates, by producing
a negative energy rate in some time periods. Thus, the OPA and MPS agree to eliminate the
anomaly by determining the non-winter energy kWh in each of its time-of-use rates by setting
those rates such that the ratio of the on-peak non-winter energy rate to the off-peak non-winter
energy rate equals the ratio of the on-peak winter energy rate to the off-peak winter energy rate.
The advisors participated in the settlement conferences that produced a stipulation
between the OPA and MPS, and recommended that the Commission approve the stipulation. No
party opposed the Stipulation.
IV. DECISION
We have reviewed the Stipulation and find that it represents a just and reasonable
resolution of the issues in this second phase of our investigation. The Stipulation, therefore,
meets one of the criteria we have set for approving stipulations: that the result is reasonable and
not contrary to any legislative mandate. The other two criteria are also met. The process that led
to this Stipulation was fair to all parties: settlement occurred after all parties had opportunity to
develop their positions and the negotiation took place at a settlement conference initiated by the
advisors to which all parties were invited. Phase I parties that did not participate in the
settlement conferences were also notified by the Examiner of the stipulated results reached by
OPA and MPS, and none of the non-participating parties filed comments or objections. Last, the
parties joining the Stipulation represent a sufficiently broad spectrum of interest such that the
Commission can be sure that there is no appearance or reality of disenfranchisement. The OPA
itself brings a broad spectrum of interest to any proceeding. Moreover, as all intervenors had the
opportunity to participate in
ORDER APPROVING - 4 - Docket No. 98-577
negotiations and to object to the settlement, but did not do so, there is no appearance or reality of
disenfranchisement.
We agree with the stipulating parties that it makes sense to eliminate the residential
inverted rate block. For a T&D utility, the inverted block - designed to discourage usage and
reflect generation costs - has little if any cost justification. We are reluctant, however, to
implement any rate design change that would result in adverse bill impacts at the time the electric
industry is restructured. Rate increases of approximately 4% to the residential users between 100
and 400 kWh is obviously such an adverse bill impact. We can accept the compromise that
achieves the preferred rate design result of eliminating the residential inverted rate block but
accomplishes the result by use of available value to avoid the adverse bill impacts. The rates that
result from this compromise produced rate decreases in the following amounts by rate class:
Residential 8.2%
Small Commercial 3.7%
Medium Commercial & Industrial 4.6 to 4.8%
Large Commercial & Industrial 4.6 to 5.2%
The overall decrease for MPS core customers is 6.1%.
We agree with the stipulating parties that the top-down result of negative or zero cost
time of use energy charges is an anomalous result that produces an unacceptable rate design. We
find that the compromise to eliminate the anomaly is reasonable and consistent with the
principles established in the Phase I Order.
To conclude, we find that the stipulation that uses some available value to write-off
35% of unrecovered Seabrook investment and some to eliminate the negative impact of the
flattening of the residential inverted rate block, and uses the remainder of available value to
levelize the likely stranded cost revenue requirement over 10 years and in an amount during the
first rate effective period that produces a modest rate decrease at the time of restructuring , is
consistent with our Phase I Order and results in setting just and reasonable T&D rates.
Dated at Augusta, Maine, this 17th day of February, 2000.
BY ORDER OF THE COMMISSION
/s/ Dennis L. Keschl
Dennis L. Keschl
Administrative Director
COMMISSIONERS VOTING FOR: Welch
Nugent
Diamond
THIS ORDER HAS BEEN DESIGNATED FOR PUBLICATION
ORDER APPROVING - 5 - Docket No. 98-577
NOTICE OF RIGHTS TO REVIEW OR APPEAL
5 M.R.S.A. section 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.
- 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. section 1320(1)-(4) and the Maine Rules of Civil
Procedure, Rule 73, et seq.
- 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. section 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.
STATE OF MAINE ) Docket No. 98-577
PUBLIC UTILITIES COMMISSION )
)
Public Utilities Commission, Re: ) January 24, 2000
Investigation of Stranded Costs, )
Transmission And Distribution Utility )
Revenue Requirements, And Rate Design of ) Stipulation
Maine Public Service Company (Phase II) )
The undersigned, being parties to this proceeding, agree as follows:
- Purpose: This Stipulation is intended to conclude those issues left unresolved or
unaddressed by the October 14, 1999 Phase I Stipulation in this Docket (approved by
the Commission by Order dated December 1, 1999). These issues are: (a) the exact
level of Maine Public Service Company's (MPS) recoverable stranded investment and
the level of recovery of that investment during the next rate-effective period; (b) the
elimination of the inverted block structure for MPS's Residential Rate A; (c) the
proper on-peak to off-peak ratio for MPS's summer TOU rates; and (d) miscellaneous
accounting orders.
- Recoverable Stranded Investment: MPS's total legitimate, verifiable and unmitigable
recoverable stranded investment for the rate-effective period, together with the total
available value from its generation asset sale, as of March 1, 2000, and subject to
Paragraph 6(c) of this Stipulation, are the amounts shown on Attachment A to this
Stipulation, which attachment is made a part of this Stipulation. The parties further
agree that MPS shall be allowed to offset its unrecovered stranded investment in
Seabrook by an amount equal to 35% of the available value from its generation asset
sale, which offset results in a total recoverable stranded investment in Seabrook of
$25,122,000, as shown on Attachment A.
- Rate Period Stranded Investment Recovery: The total annual amount of MPS's
stranded investment recoverable through retail rates for the period March 1, 2000
through February 28, 2002 shall be $12,503,000 as shown on Attachment A to this
Stipulation.
- Residential Rate A. Effective March 1, 2000, MPS shall eliminate the inclining block
for its Residential Rate A and shall replace it with a flat rate under which each
customer is charged the same amount for each kwh of usage without regard to the
number of kwhs used by that customer. The parties agree that, in order to eliminate
Rate A's inclining block structure without thereby increasing the total electric monthly
bill of any residential customer, MPS shall reduce the annual revenue requirement of
this Residential Rate A customer class in the amount of $915,000. This reduction shall
not affect the amount of the T&D utility annual revenue requirement of $16,640,000
set forth in Paragraph A(2) of the October 14, 1999 Stipulation nor the annual
recoverable stranded investment of $12,503,000 set forth in Paragraph 3 above.
1
- Summer On-Peak to Off-Peak Energy Ratios. To eliminate certain anomalies in
MPS's time of use rates that would result from the application of the top-down
methodology in the October 14, 1999 Stipulation, the parties agree that MPS shall
determine the non-winter energy (kwh) rates in each of its time of use rates by setting
them such that the ratio of the on-peak non-winter energy (kwh) rate to the off-peak
non-winter energy (kwh) rate equals the ratio of the on-peak winter energy (kwh) rate
to the off-peak winter energy (kwh) rate resulting from application of the top-down
methodology set forth in Paragraph 6C of the October 14, 1999 Stipulation for the time
of use rate class.
- Miscellaneous Accounting Orders.
Accounting Orders. In determining the amount of stranded cost recovery for the rate
effective period shown on Attachment A, the Company incorporated certain accounting
methodologies to the various elements of stranded costs. With the parties agreeing on the
amount of stranded cost recovery for the two-year period ending February 28, 2002, MPS has
requested, and by approval of this Stipulation, shall receive the following accounting orders:
- Carrying Costs on Deferred Fuel Balances. On March 1, 2000, the Company
estimates that its deferred fuel costs, as described in Paragraph 10 of the
October 14, 1999 Stipulation, will be approximately $10,919,000. Based on
the schedules on Attachment A provided to support the determination of the
$12,503,000 of stranded cost recovery, the Company will begin to amortize
$900,000 of these costs for the period March 1, 2000 to February 28, 2002.
The Company will accrue carrying costs on the unrecovered balance at the net
of tax cost of capital rate, i.e. 7.98%. The cost of capital rate was set forth in
the Phase I Stipulation and approved by the Commission.
- Amortization of Wheelabrator-Sherman Buydown Costs. Beginning January 1,
2001 and continuing through February 28, 2002, the Company will begin
amortizing the W-S buydown costs of $8,706,000 at the rate of $1,451,000 per
annum.
- Update of Estimates to Actuals. For the following items, the Company has
used its best estimates for the determination of stranded costs and will be
allowed to adjust its books of accounts for its stranded cost assets or liabilities
to reflect actual numbers through February 29, 2000 (references are to
schedules provided with Attachment A).
- Carrying costs on available value and revenue attributable to
foregone rate increase (LB-2, page 2B);
- Maine Yankee replacement fuel deferral (LB-3, page J);
2
- Available value from asset sale when all legal costs are finalized
(LB-6, page 4A); and
- Incremental power supply costs (LB-6, page 5).
- Employee Termination Costs. In determining the annual transmission and
distribution revenue requirement set forth in the October 14, 1999 Stipulation,
the Company had estimated termination costs associated with personnel
displaced by the sale of the Company's generating assets. The Company will
be allowed to amortize these costs over four years. In addition, the Company
will be allowed to defer all verifiable termination costs that exceed its estimate
of $462,000. At the next rate review, the Company will amortize over two
years, the balance of any remaining termination costs.
- Stipulation Not Precedential. The making of this Stipulation by the parties shall not
constitute precedent as to any matter of law or fact, nor shall it permit any party from
making any contention or exercising any right, including rights of appeal, in any other
Commission proceeding or investigation or any other trial or action.
In Witness Whereof, the parties have caused this Stipulation to be signed by their
respective attorneys.
January 24, 2000 MAINE PUBLIC SERVICE COMPANY
By /s/ Stephen A. Johnson
Stephen A. Johnson, General Counsel
January 24, 2000 OFFICE OF THE PUBLIC ADVOCATE
By /s/ William C. Black
__________________ William C. Black
3
1. 16 U.S.C. section 824B (1994).
2. Among the generating assets to be sold in Maine Public's ownership share
in the William F. Wyman Unit No. 4 (Wyman 4). Transmission Service to
the various Public and municipal utilities that jointly own Wyman 4 is
provided under the William F. Wyman Transmission Agreement (Wyman
Transmission Agreement). Concurrently with the application, Maine Public
requested, pursuant to section 205 of the FPA, that its rights and obligations
under the Wyman Transmission Agreement be assumed by PDI-NE as part
of the proposed transaction. By unpublished letter order issued March 12,
1999, in Docket No. ER99-1692-000, the Commission accepted the transfer
of Maine Public's rights and obligations under the Wyman Transmission
Agreement to PDI-NE.
3. Energy Atlantic, LLC, 85 FERC paragraph 61,058 (1998).
4. On February 24, 1999, in Docket No. EC99-1936-000, PDI-NE and PDI-Can
filed, pursuant to section 205 of the FPA, a joint application for Commission
authorization to engage in sales of electricity at market-based rates. That
application will be addressed by a separate Commission order.
5. The joint motion also requests that PDI-NE be allowed to join as an applicant
in the instant application.
6. 18 C.F.R. section 385,214 (a) (2) (1998).
7. Application at 13 (citing Maine Public Service Company, 71 FERC
paragraph 61,249 (1995) and unpublished letter order issued June 26, 1998,
in Docket No. ER95-851-003).
8. Application at 12-13.
9. 16 U.S.C. section 825d (1994).
10. The Northern Maine ISA will include the transmission systems of the
investor-owned and cooperatively-owned transmission and distribution
systems in the northern-most part of the State of Maine, located in portions
of Aroostook, Washington and Penobscot Counties (Northern Maine). Its
members will include all investor-owned, cooperatively-owned, and
municipally-owned utilities, generators, suppliers of energy and large retail
customers in Northern Maine.
11. 18 C.F.R. section 2.21 (1999). The Commission's policy on RTGs is found
in the Commission's Policy Statement Regarding Regional Transmission
Groups, 58 Fed. Reg. 41,626 (1993), FERC Stats. & Regs. paragraph 30,976
(1993) (RTG Policy Statement).
12. See Northern Maine ISA's Filing at 1.
13. Id. at 3-4
14. Id. at 2. In addition to Maine Public Service, other load-serving entities
located in this isolated section of Maine are EMEC, which owns transmission
facilities which are interconnected with New Brunswick Power, but not with
Maine Public Service, and two municipals that have historically purchased
requirements power from Maine Public Service: Houlton and Van Buren.
15. See id. at 2.
16. Id. at 8.
17. Id. at 5.
18. Id.
19. Northern Maine ISA states that any such amendment to the market rules will
be filed before December 31, 1999. Northern Maine ISA's Filing at 7.
20. The two main TOs in Northern Maine are Maine Public Service and EMEC.
Northern Maine ISA states that, as a public utility, Maine Public Service has
an open access transmission tariff on file with the Commission. EMEC is not
a public utility because it is a borrower from the Rural Utilities Service
(RUS). Northern Maine ISA asserts that EMEC has nevertheless agreed to
prepare and to file with the Northern Maine ISA an open access transmission
tariff that will, to the extent feasible on the EMEC system, provide
transmission access over the EMEC system that is comparable to that
provided by the Maine Public Service open access transmission tariff.
Northern Maine ISA states that the EMEC open access transmission tariff
will be filed with the Northern Maine ISA and become effective prior to the
effective date of the Tariff.
21. The two main TSOs in Northern Maine are Maine Public Service and EMEC.
22. Northern Maine ISA's Filing at 12.
23. Id. at Attachment A, Tariff Original Sheet No. 24.
24. Id. at Attachment A, Tariff Original Sheet No. 26
25. Id. at Attachment A, Tariff Original Sheet No. 29.
26. We note that the ISA Tariff does not revise the rates for transmission service
under Maine Public Service's open access transmission tariff on file with the
Commission.
27. See New England Power Pool, 83 FERC paragraph 61,045 at 61,232-33
(1998).
28. RTG Policy Statement, FERC Stats. & Regs. at 30,872-76; Mid-Continent
Area Power Pool, 76 FERC paragraph 61,261 at 62,340 (1996), reh'g denied,
87 FERC paragraph 61,075 (1999).
29. See, e.g., Southwest Regional Transmission Association, 69 FERC paragraph
61,100 at 61,389, 61,391-404 (1994)(SWRTA); Western Regional
Transmission Association, 69 FERC paragraph 61,099 at 61,376-85, order on
reh'g, 69 FERC paragraph 61,352 (1994), order on compliance filing, 71
FERC paragraph 61,158 (1995)(WRTA).
30. See 18 C.F.R. section 2.21(b)-(c) (1999).
31. See SWRTA, 69 FERC at 61,397-98;WRTA, 69 FERC at 61,380.
32. RTG Policy Statement at 30,873.
33. Id. at 30,874.
34. See Northern Maine ISA's Filing at Attachment C.
35. RTG Policy Statement at 30,874.
36. As noted above, EMEC has committed to file with the Northern Maine ISA
an open access transmission tariff that will, to the extent feasible on the
EMEC system, provide transmission access over the EMEC system that is
comparable to that provided by the Maine Public Service Tariff. The EMEC
Tariff will be filed with the Northern Maine ISA and effective prior to the
effective date of the ISA Tariff. See Northern Maine ISA's Filing at 10.
37. See SWRTA, 69 FERC AT 61,398-400.
38. RTG Policy Statement at 30,875.
39. RTG Policy Statement at 30,875, 30,877-78.
40. Section 9 includes detailed provisions regarding selection of an arbitrator,
allocation of costs, location of the hearing, rules and proceedings, and appeals
of an arbitrator's decision.
41. Id. at 30,875-76.
42. Northern Maine ISA's Filing at 24.
43. See. e.g., Entergy Nuclear Generation Company, 86 FERC paragraph 61,142
at 61,503 (1999); GS Electric Generating Cooperative, Inc., et al., 81 FERC
paragraph 61,042 at 61,231 (1997).
44. Chapter 307 implements section 3204 of the Restructuring Act that does not
require the divestiture of QF contracts but does require the periodic sale of the contractual
rights to the capacity and energy.
45. In the years 2002 through 2006, MPS forecasted the need to create additional
regulatory assets of $600,000 to $2.1 million per year in order to levelize the revenue
requirement in those years.
46. The stranded investment revenue requirement for the unrecovered Seabrook
investment, i.e. the unamortized Seabrook investment grossed up for taxes, is
$25,122,000.
