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SECURITIES
AND EXCHANGE COMMISSION
Washington, D. C.
20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SEC. 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
Commission File No. 333-103749
Maine &
Maritimes Corporation
(Exact name of registrant as specified in
its charter)
Maine
(State or other jurisdiction of
incorporation or organization)
30-0155348
(I.R.S. Employer Identification No.)
209 State
Street, Presque Isle, Maine
(Address of principal executive offices)
04769
(Zip Code)
Registrant’s telephone number, including area code: 207-760-2499
Securities registered pursuant to Section 12(b) of the Act:
Title of each class: Common Stock, $7.00 par value
Name of each exchange on which registered: 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 ý. No o.
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. o
Indicate
by check mark whether the registrant is an accelerated filer (as defined in
Rule 12b-2 of the Act).
Yes o. No ý.
Aggregate market value of the voting stock held by non-affiliates at
June 30, 2003: $51,189,661.
The number of shares outstanding of each of the issuer’s classes of
common stock as of March 15, 2004.
Common Stock, $7.00 par
value – 1,580,701 shares
DOCUMENTS INCORPORATED BY REFERENCE
The
Company’s definitive proxy statement to be filed pursuant to Regulation 14A no
later than 120 days after December 31, 2003, which is the end of the fiscal
year covered by this report, is incorporated by reference into Part III.
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MAINE
& MARITIMES CORPORATION
FORM 10-K
For the Fiscal Year Ended December 31, 2003
For Glossary of Terms, see Page 95
TABLE OF CONTENTS
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PART I
Item 1. Business
General
Maine
& Maritimes Corporation (“MAM” or the “Company”), a Maine corporation,
became a holding company effective June 30, 2003. MAM owns all of the common stock of Maine Public Service Company
(“MPS”). All other shares of MPS common
stock were converted into an equal number of shares of MAM common stock, which
are listed on the American Stock Exchange (“AMEX”) under the symbol “MAM.” The reorganization into a holding company
was approved by MPS’s shareholders at its annual meeting on May 30, 2003. The U.S. Securities and Exchange Commission
(“SEC”) had previously accepted MAM’s S-4A Registration Statement for
registration. Other required state and
federal regulatory agencies issued necessary approvals on various dates in
2003. Financial results and amounts
shown through 2002 and the first three months of 2003 were reported by MPS.
MAM
is the parent holding company for MPS, Energy Atlantic, LLC (“EA”), and Maine
& Maritimes Energy Services Company (“MAMES”). Maine & New Brunswick Electrical Power Company, Ltd
(“Me&NB”), is a wholly-owned Canadian subsidiary of MPS. MAMES (dba “The Maricor Group”) is the
parent company of Maricor Ltd (“Maricor”), also a wholly-owned Canadian
subsidiary. General descriptions of
these companies and subsidiaries are discussed more fully below.
Maine
& Maritimes Corporation and Subsidiaries
• MPS
is a regulated electric transmission and distribution utility serving all of
Aroostook County and a portion of Penobscot County in northern Maine.
• Maine
& New Brunswick Electrical Power Company, Ltd, an inactive Canadian
subsidiary of MPS, formerly owned MPS’s Canadian electric generation assets.
• Energy
Atlantic, LLC is a licensed, but currently inactive Competitive Energy Supplier
(“CES”) of retail electricity and formerly served the northern and central
regions of the state of Maine.
• Maine
& Maritimes Energy Services Company (dba “The Maricor Group”) is a
development, engineering, energy efficiency and asset management firm focused
on markets in the United States providing fee-for-service mechanical and
electrical engineering services.
• Maricor
Ltd is a Canadian subsidiary of Maine & Maritimes Energy Services Company,
whose principal business is primarily the delivery of similar products and
services as MAMES, but in Canadian markets.
Discussion and Description of the
Company’s Growth Strategy
MPS’s
decision to convert to a holding company structure and begin implementation of
a diversification and growth strategy was based on a combination of regulatory
and economic factors including, but not limited to: (a) the impacts of
deregulation and generation divestiture on MPS’s revenue model, (b) flat to
declining demographic and economic
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conditions
within MPS’s service area; (c) regulatory constraints or barriers to
implementation of a growth strategy under MPS’s organizational structure; (d) a
declining rate base as a result of reductions in stranded costs as regulatory
assets; and (e) the strategic objective to implement an effective risk
management structure associated with the Company’s overall growth strategy.
As
a result of Maine’s deregulation and MPS’s generation divestiture, MPS no
longer serves as a vertically integrated electric utility. With the exception of stranded cost
recovery, MPS’s revenues come almost exclusively from regulated transmission
and distribution services associated with transporting electric supply. MPS does receive varying returns on its
stranded regulatory assets, as well as varying returns on its regulated
transmission and distribution rate bases.
Generally, stranded cost represents the difference in value or contract
value of generation assets in a regulated environment, as compared with market
values of these same assets or contracts for purchased power agreements. In a regulated regime, investor-owned public
utilities are allowed to make a “fair” rate of return on their prudently
invested capital. In practice, regulators
set the price of electricity so that the utility receives enough income to pay
its financial obligations plus a reasonable return on its fixed
investments. In effect, historical or
accounting costs of asset installations determine the current market value of
capital. Regulators adjust the revenue
stream up or down to allow a public utility to earn the approved rate of return
on the book value of its capital, which is also known in a regulatory context
as its “rate base.” MPS continues to
earn regulated rates of return on its transmission and distribution
assets. MPS’s distribution services are
regulated by the Maine Public Utilities Commission (the “MPUC”) and its
transmission services are regulated by the U.S. Federal Energy Regulatory
Commission (“FERC”).
Based
on MPS’s current amortization of stranded costs and approved stranded cost
rates of return approved by the MPUC, and subject to a number of variables
embedded in the calculation of those stranded costs, the majority of MPS’s
stranded cost should be recovered by the end of 2012. A significant portion of MPS’s stranded costs are associated with
an existing non-utility generator (“NUG”) supply contract referred to in this
document as the “Wheelabrator-Sherman NUG Contract.” The Wheelabrator-Sherman NUG Contract resulted from the passage
by the U.S. Congress of the 1978 Public Utilities Regulatory Policy Act
(“PURPA”) and is summarized more fully below.
The facility itself is a small bio-mass (principally wood chip) electric
generation facility. Over approximately
the next eight years, MPS’s rate base will decline as these and other stranded
costs are reduced or eliminated.
Management and the Board of Directors also believe that MPS’s rate base
will continue to decline as a result of: (a) the economic impact of
deregulation and generation divestiture on MPS’s core revenue model; (b) MPS’s
economically lagging service area; and (c) regulatory risks in connection with
rate making and stranded cost recovery.
Based on management’s and the Board of Directors’ assessment of MPS’s
declining rate base, the decision was made to create a holding company, subject
to shareholder approval, and to implement a comprehensive growth strategy.
Although
the majority of MPS’s stranded cost rate base will decline gradually over
approximately the next eight years, MPS believes it will experience deferred
stranded cost freed-up cash flows during the period from 2007 through 2012 as
certain stranded costs are recovered.
This is a result of MPS’s historical decision to levelize its stranded
cost portfolio and defer full recovery associated with its Wheelabrator-Sherman
NUG Contract, These deferred stranded cost freed-up cash flows will not impact
net income. Current plans for the
anticipated stranded cost freed-up cash flows include: (a) utilizing such funds
to reduce debt; (b) maintaining an optimum regulatory capital structure; and
(c) to dividend a portion of the stranded cost freed-up cash flows to the
parent MAM for the purpose of financing in part or in whole potential
acquisitions consistent with the Company’s growth strategy. While MPS believes it will receive full
stranded cost recovery and recovery of deferred collections, it cannot predict
with certainty future regulatory and/or legislative actions. Regulatory and legislative risks may exist
relative to full stranded cost recovery.
In addition there are a number of variables, discussed in more detail
below that may affect the timing and magnitude of MPS’s stranded cost recovery.
Management
and the Board of Directors have adopted what they believe to be a realistic and
conservative growth strategy, focusing primarily, but not exclusively, on
market opportunities within New England and Atlantic Canada. As part of the Company’s growth and business
strategy, focus and investments are being placed on strategies to improve the
overall performance, system reliability, economics and efficiencies of MPS’s
transmission and distribution systems.
These strategies include the adoption of new productivity enhancing
technologies, changes in core business processes, adoption of integrated asset
management strategies, and development and implementation of long-term
transmission and distribution plans.
These plans may also include the construction of additional regulated
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transmission
assets. The goals of these efforts are
to reduce overall annual capital, operating, and maintenance expenditures,
while improving system and customer service performance.
MAM’s
growth strategy centers on a diversification approach that expands the
Company’s business and revenue model to include, without limitation, mechanical
and electrical engineering services, energy efficiency solutions, air emissions
reductions, asset/facilities management related services and asset/facility
ownership, in addition to its continuing focus on regulated and unregulated
utility services. Unregulated utility
services may include, but not be limited to, energy supply management and
unregulated energy assets, such as central utility plants.
The
Company is continuing to evaluate potential regulated and unregulated utility
acquisitions, such as small electric utilities, local natural gas distribution
companies, fuel oil and propane distributors, electric transmission projects
and mid-stream natural gas assets across North America. However, the Company cannot assure that such
acquisitions can or will be accomplished.
Utility-related acquisitions are intended to seek to leverage MPS’s and
other subsidiaries’ existing operating infrastructure, including without
limitation, call center and collections operations, telecommunications
technologies, billing and information technology applications, engineering
capabilities, asset management systems, regulatory experience, and management
expertise. MAM’s proposed overall
growth strategy will be heavily influenced by acquisitions that meet certain
desired strategic and financial criteria within the general categories defined
below. Implementation of the
acquisition strategy is dependent upon, among other things, MAM’s and its
subsidiaries’ ability to raise sufficient capital. MAM believes that it can raise necessary capital to implement its
acquisition strategy, but cannot assure investors of this ability.
Organizational Overview of Proposed Strategic Vision
Showing Examples of Potential Business Sector Acquisitions
* MAM does not warrant that it can or will
implement acquisitions in each of the revenue models. However, acquisitions in
each of the revenue models will be evaluated and are under consideration.
As
a part of the process in developing the Company’s growth strategy, market and
public policy trends were analyzed for the Atlantic Canada and New England
regions. As a result of these analyses,
it appears that a number of critical economic, environmental, energy, and
infrastructure trends are converging within these regions. In Atlantic Canada, electric transmission
appears to be significantly limited and the adequacy of on-peak electric
generation also appears to be unclear.
The region has historically been highly dependent on oil as an energy
source and has limited alternative fuel choice options, such as natural gas or
other fuels for its electric generation.
As a result, Atlantic
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Canada
may face near-term on-peak energy shortages and increasing energy price
issues. The Company believes both
regions appear to face complex energy challenges in the near to long-term. Also, should the cost of energy rise and
availability of energy supplies come into question, air quality concerns and
related regulation and legislation may inhibit the construction of new,
adequate generation within the region.
Canada’s adoption of the Kyoto Protocol and the 28th Annual
Conference of the New England Governors and the eastern Canadian Premiers
Resolution 28-7, a resolution concerning environmental projects and issues, are
examples of increasing public policies that are placing more stringent air
quality requirements on the construction or refurbishment of energy producing
or using facilities. Management also
believes the combination of energy price, energy availability, and air quality
concerns is exacerbated within the region due to additional apparent
uncertainty concerning the economics and approval for the refurbishment and
retooling of older, existing electric generation facilities that may include,
for example a nuclear generation facility within New Brunswick, Canada. Management believes that these public policy
issues are placing new pressures on governments and organizations to improve
energy efficiency, gain greater control of energy costs, and reduce air
emissions. At the same time, Management
believes the two regions also face the reality that tax revenues and existing
economic growth are inadequate to fund infrastructure renewals associated with
schools, hospitals, municipal operations and universities. This recognition appears to be bringing
increased focus on the significant deferred maintenance liabilities of public
assets, and the requirement to ensure that capital dollars for facility
renewals and replacements are spent in the most optimal manner to extend the
life of such facilities, i.e. the facility asset lifecycles. Consequently, Management believes that
governments, both domestic and foreign, are beginning to require lifecycle
asset management plans and the determination of lifecycle costs before
additional capital dollars are spent for facility renewals and
replacements. The Company’s overall
growth strategy is primarily based on these beliefs, issues, observed trends,
analyses and conclusions.
Utilizing
a combination of strategic acquisitions and non-acquisition growth, the
Company’s business model, includes the acquisition of mechanical and electrical
engineering companies offering asset lifecycle management and engineering
services. Through the integration of
engineering skills and certain asset lifecycle management software accessed by
the Company or its subsidiaries; MAMES’ and Maricor’s services are being
offered to improve facility energy efficiency, define and reduce deferred
maintenance, extend asset lifecycles, and reduce air emissions. These services are also intended to enhance
the economic efficiency of a facility’s electric and mechanical systems
resulting in reduced operating costs.
In addition, the Company and its subsidiaries are focused on identifying
and developing energy asset related projects that may consist of either small
“green field” development projects located on or related to a customer’s
premises, or the acquisition of a customer’s energy assets, such as a central
utility plant or a district energy project, with a long-term contract from one
or more customers for the energy asset’s output. These development projects may, or may not involve a third party
financing and ownership entity. The
Company intends to market such services within Atlantic Canada and New England,
however it does not intend to be geographically limited to these regions. Specific primary market sectors of emphasis
include, without limitation, the government, university, school, hospital,
commercial and institutional markets.
MAMES and Maricor also offer fee-for-service engineering services, which
are provided to a broader cross-section of businesses and industries within the
regions.
The
Company’s intended strategic plan, subject to market opportunities and
conditions, also includes the potential acquisition of a small, regional real
estate development and facilities management business, which is intended to
compliment the Company’s asset or facilities-centric engineering business
model. Efforts are on-going to evaluate
market opportunities for the acquisition of such a firm within the Atlantic
Canada and New England regions. The Company’s
intended objective is to acquire a small to medium real estate portfolio as a
part of its acquisition of a real estate development and management
company. The targeted real estate
portfolio would ideally consist of non-operating and non-retail properties
within second and third tier growth markets within the target region, with an
increasing focus on the development of public facilities with long-term leases
matching financing terms. The Company’s
entry and timing of such an entry into this market is primarily dependent upon
market conditions and the availability of an acquisition on economically
acceptable terms. The Company cannot
warrant that it can or will succeed in achieving such an acquisition.
Financing
of the Company’s growth strategy, depending on the specific acquisition target,
may take the form of a number of different financing structures involving cash,
equities and/or debt. Financing may
include, without limitation, the issuance of additional common or preferred
stock, vendor take backs, senior debt, private mezzanine debt securities, tax-exempt
government bonds, cash or acquisition earn-outs. In addition to its
compatibility with the Company’s growth strategy, each acquisition target is
also being evaluated based on its individual economic and strategic merits
relative to long-term shareholder value.
As the Company implements its growth strategy, a more definitive stock
dividend policy may be adopted. Such a
policy, if adopted by the Board of Directors, would be
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intended
to provide guidance relative to a definitive dividend payout range. The Company, however, remains committed to
maintaining a market competitive dividend yield with an increasing focus on a
combination of yield and stock value growth.
However, the Company cannot warrant or define future dividends or share
value.
As
a first step in implementing the Company’s growth strategy, in November 2003,
MAM formed MAMES and its Canadian subsidiary, Maricor in Canada. MAMES and Maricor provide facilities-based
mechanical and electrical engineering services, asset lifecycle management
services and solutions, energy efficiency, energy reliability, and emissions
reduction services. Maricor’s first
strategic acquisition, Eastcan Consultants, Inc, (“Eastcan”) took place on
December 1, 2003. Eastcan is a
regional, mechanical and electrical engineering firm, focused on the Atlantic
Canada markets and headquartered in Moncton, New Brunswick, Canada, with an
office in Saint John, New Brunswick, Canada.
The acquisition represents an initial platform acquisition from which to
build and/or acquire additional capabilities.
MAMES, dba “The Maricor Group” intends to continue to evaluate
engineering company acquisitions that provide market entry points into key markets
within the target regions of New England, the U.S. and Atlantic Canada.
Description
of Maine Public Service Company and Maine and New Brunswick Electrical Power
Company, Limited
MPS
was originally incorporated in the United States as the Gould Electric Company
(“Gould”) in April, 1917 by a special act of the Maine legislature in
connection with the purchase and lease of all of the assets of the Maine and
New Brunswick Electrical Power Company, Limited, a Canadian company. Me&NB, currently a wholly-owned Canadian
subsidiary of MPS, was incorporated in 1903 under the laws of the Province of
New Brunswick, Canada. Following the
sale of its assets to Gould, Me&NB remained a subsidiary of Gould, and
subsequently MPS. Me&NB was
primarily a hydro-electric generating company.
It owned and operated the Tinker hydro-electric station in New
Brunswick, Canada, until June 8, 1999, when these assets were sold by MPS to
WPS Power Development, Inc. (“WPS-PDI”), a subsidiary of WPS Resources
Corporation (“WPS”). Prior to the
generating asset sale, Me&NB sold energy not needed to supply its wholesale
New Brunswick, Canada customers, to MPS.
For the period 2000-2003, Me&NB has been inactive and did not have
unaffiliated customer revenues.
Following
its incorporation in the United States, Gould changed its name to Maine Public
Service Company in August, 1929. MPS
was a privately held subsidiary of the Consolidated Electric & Gas Company
until 1947, when its capital stock was sold as a result of Consolidated Electric
& Gas Company’s forced divestiture.
From 1947 until its corporate reorganization in 2003, MPS was the
corporate parent and traded under the stock symbol “MPS” on the AMEX. MPS, until its generating assets were sold
on June 8, 1999, produced and, until March 1, 2000, purchased electric energy for
retail and wholesale customers. MPS
continues to provide transmission services to former wholesale energy customers
and transmission and distribution services to retail customers in the service
territory. Geographically, its service
territory is located in a region of northern Maine comprised of all of
Aroostook County and a portion of Penobscot County. The service area covers a region approximately 120 miles long and
30 miles wide, with a population of approximately 72,000. Since March 1, 2000, the date retail
electric competition in Maine commenced, customers in MPS’s service territory
have been purchasing energy from suppliers other than MPS. This energy comes from Competitive
Electricity Providers (“CEP”) or, if customers are unable or do not wish to
choose a competitive supplier, the Standard Offer Service (“SOS”)
provider. SOS providers are determined
through a bid process conducted by the MPUC.
By
regulatory order, on June 4, 1984, MPS entered into a Power Purchase Agreement
(“PPA”) with the Sherman Power Company, which assigned its interest in the
agreement to the Wheelabrator-Sherman Energy Company (“WS”), formerly
Signal-Sherman Energy Company, for 17.6 megawatts of capacity, the delivery of
which began on July, 1986. As stated
above, the WS facility is a NUG and qualifying facility as that term is defined
by PURPA. This PPA formed the basis of
what was to become the Wheelabrator-Sherman NUG Contract. The stated legislative intent of PURPA was
to encourage more energy-efficient and environmentally-friendly commercial
energy production. PURPA defined a new
class of energy producer called a qualifying facility (“QF”). QFs are small-scale producers of commercial
energy who normally self-generate energy for their own needs and/or may sell the
output under a PPA to a regulated utility.
When a facility of this type meets the FERC’s requirements for
ownership, size and efficiency, utility companies are obligated under PURPA to
purchase energy from these facilities based on a pricing structure referred to
in a regulatory context as avoided cost rates.
In the case of WS, the avoided cost rates were defined by the MPUC at
the avoided cost rate of another facility, the Seabrook nuclear facility’s
fully embedded production cost, making these rates highly favorable to the
producer. The difference between these
avoided costs rates and the market rate that would result
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from
an arms length negotiation for the producer’s electric capacity is an important
component of MPS’s WS stranded costs.
The
original Wheelabrator-Sherman NUG Contract was scheduled to expire at the end
of 2000; however, either party had the option to renew the contract for an
additional fifteen years. MPS and WS
agreed to amend the Wheelabrator-Sherman NUG Contract with the amendment
approved by the MPUC in December, 1997.
Under the terms of this amendment, WS agreed to reductions in the price
of purchased power of approximately $10 million over the contract’s current term. MPS and WS also agreed to renew the contract
for an additional six years at agreed-upon prices. MPS made an up-front payment to WS 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, as determined by the MPUC in its December,
1997 order and, based on an MPUC order, included in stranded costs and
recovered in the rates of the transmission and distribution utility, beginning
January 1, 2001. The amended contract
helped relieve the financial pressure caused by the closure of Maine Yankee in
1997, as well as the need for substantial increases in MPS’s retail rates, and
also reduced MPS’s stranded costs.
Every
two years, the WS output is sold via competitive bids, with the bidding process
monitored by the MPUC. The sale of the
WS output offsets the WS costs in determining this component of MPS’s stranded
costs. For the period March 1, 2000 to
February 28, 2002, and from March 1, 2004 to the end of the
Wheelabrator-Sherman NUG Contract, December 31, 2006, WPS-PDI was the
successful bidder. For the period March
1, 2002 to February 29, 2004, EA took delivery of 40% of WS’s output, while
WPS-PDI took the 60% remainder. MPS
records the above-market cost of Wheelabrator-Sherman NUG Contract as a
stranded cost.
As
stated above, MPS’s Canadian Subsidiary, Me&NB has been inactive for the
period of 2001-2003, as reflected in the table below.
MPS’s
research and analyses of its service area indicate that MPS’s service area’s
economy, once heavily influenced by a significant military presence, continues
to be dependent upon agricultural and the forest products industries. Potato farming and processing and the
manufacturing of forest products, principally lumber, plywood, and oriented
strand board, continue to be dominant economic forces within
MPS’s service area. The growing of
broccoli has added diversity to the region’s agricultural economic base. Tourism, particularly related to
snowmobiling and skiing, appears to be playing an increasingly significant role
in the area’s economy. The medical
industry represents a significant positive and growing economic force within
the region, serving as a leading employer and job creation sector. However, data appears to suggest that the
northern Maine economy continues to lag behind national economic trends and is
experiencing population losses based on census data and recent projections,
particularly among the service area’s youth and young adults. Attracting new businesses and jobs to
northern Maine in an effort to reverse out-migration trends appears to be a
continuing challenge to the area’s leaders and businesses, including MPS. As a result of its service area’s economic
challenges, MPS has taken a lead role in forming a public/private partnership
for economic progress in cooperation with the Northern Maine Development
Commission. Managed by a private-sector
investors’ council, MPS and its staff are serving as a private sector leader in
helping to execute a rational and results-oriented economic development
program. The Aroostook Partnership for
Progress’s (“APP’s”) efforts are intended to increase the area’s emphasis on
economic development through improved focus and funding for economic
development.
Energy Atlantic,
LLC
EA
participated in the wholesale power market during 1999 and until March 1, 2000,
when it began selling energy in the retail electricity market within the state
of Maine. The retail market consists of
two sectors, Standard Offer Service (“SOS”) and Competitive Energy Supply
(“CES”), as mentioned above. The MPUC
requests bids for SOS in each utility service territory. As a result of this bidding process, EA was the
SOS provider in Central Maine Power Company’s (“CMP’s”) territory from March 1,
2000, until its contract expired on February 28, 2002. Within MPS’s service territory, EA provided
20% of the medium non-residential SOS from March 1, 2000 until February 28,
2001.
EA
also provided energy to several large commercial customers in CMP’s territory
under one-year CES contracts, which expired throughout 2001. EA, along with its wholesale energy
supplier, was not successful in obtaining any of the SOS in MPS’s service
territory starting March 1, 2001, nor CMP’s service territory starting March 1,
2002.
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Originally,
power for the sales noted above was obtained under an exclusive wholesale power
sales agreement with Engage Energy America, LLC, (“Engage”), which expired
February 28, 2002.
As
part of a contract settlement between Engage and EA reached in May 2001, EA was
allowed to purchase energy from additional sources. EA secured several wholesale sources of power, enabling it to
participate in competitive markets within Maine. EA’s CES sales to retail customers during 2003 produced far less
operating margin than EA had previously earned from SOS in CMP’s
territory. On February 24, 2003, EA
announced its intent to withdraw from the northern Maine market due to the lack
of profitability and perceived risk profile in that market resulting from an
illiquid wholesale market, inability to obtain price differentiated wholesale
electric products, and other factors.
EA continued to serve its existing contracts in northern Maine until their
February 27, 2004, expiration date. In
addition, EA has not renewed its wholesale agreement for southern Maine supply
and has not renewed retail contracts within this region. Management has ceased active retail CES
within the state of Maine until market conditions, the availability of supply,
the mandate for stringent credit requirements and risk environment
improve. Management will continue to
monitor both U.S. and Canadian deregulated markets to determine the appropriate
timing for possible re-entry into the deregulated retail market. For further information regarding EA, its
contract settlement with Engage and its future business plans, see Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of
Operations, “Energy Atlantic Activities,” such information is incorporated in
this section by this reference.
Maine &
Maritimes Energy Services Company (dba “The Maricor Group”) and Maricor Ltd
In
November 2003, MAM formed the wholly-owned subsidiaries MAMES in the United
States (dba “The Maricor Group”), and its Canadian subsidiary, Maricor. MAMES and Maricor are businesses organized
to provide, among other things, energy efficiency, energy reliability, air
emissions reduction, fee-for-service mechanical and electrical engineering and
lifecycle asset management services primarily within eastern Canadian provinces
and New England. MAMES is headquartered
in Presque Isle, Maine with offices in Portland, Maine and Rockland,
Massachusetts.
Maricor’s
first strategic acquisition, Eastcan Consultants, Inc, (“Eastcan”) took place
on December 1, 2003. Eastcan, now an
operating division of Maricor, is a regional, mechanical and electrical
engineering firm headquartered in Moncton, New Brunswick, Canada, with an
office in St. John, New Brunswick, Canada.
Eastcan was formed in 1978, in connection with the amalgamation of
several engineering firms in the Moncton, New Brunswick area. Eastcan’s combined historical experience is
well in excess of five thousand building projects. Eastcan’s clients generally include architectural firms,
municipal, provincial and federal governments, private institutional,
commercial facility owners and industrial or manufacturing operations. Mechanical and electrical engineering
service disciplines provided by the Eastcan Division of Maricor include,
without limitation, the following:
Mechanical Engineering Services:
• Plumbing
• Heating
• Ventilation
• Air Conditioning
• Energy Conservation Studies and Audits
• Reports & Investigations
• Process Piping
• Fire Protection Systems
• Boiler Plants
• Petroleum Storage and Handling Systems
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Electrical Engineering Services:
• Lighting Calculations and Layouts
• Power Distribution (Buildings, Industrial
Plants, Process Equipment)
• Power Quality (Emergency generators, UPS
systems, Harmonic cancellations)
• Fire Alarm Systems
• Intrusion Alarm System Integration
• Public address system
• Power Factor Correction
• Reports & Investigations
To
complement Maricor’s service and product offerings, MAM and MAMES have
partnered with Delinea Corporation of Dallas, Texas, a leading software
application and business process outsourcing company focused on the energy
industry, and acquired exclusive marketing rights to their Strategic Asset
Management (“SAM”) technology-based solutions for select markets within the
U.S. and Canada.
Delinea’s
SAM offerings are industry-leading solutions for organizations that are seeking
to preserve and maintain the value of their investments in infrastructure,
facilities and fixed assets. SAM
provides the technology and services required to effectively manage the total
lifecycle of capital assets, as well as the daily operations of facilities and
fixed assets. Its strategic planning
capabilities are used to quantify, prioritize and optimize the capital
investments required to maintain and preserve facilities and assets, while
providing decision-making support to effectively manage these critical
requirements in accordance with capital budgets and available funding.
Page 11
of 95
Financial Information about Foreign and Domestic
Operations
(In Thousands of U.S. Dollars)
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
Revenues from Unaffiliated Customers:
|
|
|
|
|
|
|
|
|
MAM-United States
|
|
—
|
|
—
|
|
—
|
|
|
MPS-United States
|
|
31,739
|
|
31,401
|
|
31,780
|
|
|
Energy Atlantic-United States
|
|
6,064
|
|
6,901
|
|
15,771
|
|
|
Energy Atlantic-U.S. - SOS Margin
|
|
—
|
|
5,802
|
|
2,147
|
|
|
Total Domestic
|
|
37,803
|
|
44,104
|
|
49,698
|
|
|
* Subsidiaries-Canada
|
|
58
|
|
—
|
|
—
|
|
|
Total
|
|
37,861
|
|
44,104
|
|
49,698
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany Revenues:
|
|
|
|
|
|
|
|
|
MAM-United States
|
|
—
|
|
—
|
|
—
|
|
|
MPS-United States
|
|
—
|
|
—
|
|
—
|
|
|
EA-United States
|
|
9
|
|
9
|
|
3
|
|
|
Total Domestic
|
|
9
|
|
9
|
|
3
|
|
|
Subsidiaries-Canada
|
|
—
|
|
—
|
|
—
|
|
|
Total
|
|
9
|
|
9
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss):
|
|
|
|
|
|
|
|
|
MAM-United States
|
|
(457
|
)
|
—
|
|
—
|
|
|
MPS-United States
|
|
3,704
|
|
3,523
|
|
5,379
|
|
|
EA-United States
|
|
(164
|
)
|
3,349
|
|
1,006
|
|
|
Total Domestic
|
|
3,083
|
|
6,872
|
|
6,385
|
|
|
Subsidiaries-Canada
|
|
77
|
|
(7
|
)
|
(25
|
)
|
|
Total
|
|
3,160
|
|
6,865
|
|
6,360
|
|
|
Net Income (Loss)
|
|
|
|
|
|
|
|
|
MAM-United States
|
|
(418
|
)
|
—
|
|
—
|
|
|
MPS-United States
|
|
3,238
|
|
3,089
|
|
4,331
|
|
|
EA-United States
|
|
(116
|
)
|
3,444
|
|
897
|
|
|
Total Domestic
|
|
2,704
|
|
6,533
|
|
5,228
|
|
|
Subsidiaries-Canada
|
|
102
|
|
10
|
|
9
|
|
|
Total
|
|
2,806
|
|
6,543
|
|
5,237
|
|
|
Identifiable Assets:
|
|
|
|
|
|
|
|
|
MAM-United States
|
|
2,408
|
|
—
|
|
—
|
|
|
MPS-United States
|
|
134,996
|
|
134,883
|
|
136,931
|
|
|
EA-United States
|
|
2,024
|
|
6,324
|
|
5,632
|
|
|
Total Domestic
|
|
139,428
|
|
141,207
|
|
142,563
|
|
|
Subsidiaries-Canada
|
|
1,841
|
|
779
|
|
772
|
|
|
Total
|
|
141,269
|
|
141,986
|
|
143,335
|
|
The identifiable assets, by company, are those assets used in each
company’s operations, excluding intercompany receivables and investments. For 2003 and 2002, identifiable assets
reflects the reclassification of accrued removal obligations as a liability
from accumulated depreciation.
* The term “Subsidiaries Canada” above includes all
applicable financial information for Me&NB and Maricor.
Regulation and Rates
The
information with respect to regulation and rates is presented in Item 3 below,
“Legal Proceedings,” such information is incorporated in this section by this
reference.
Page 12
of 95
Franchises and Competition
Except
for consumers served at retail by municipal electric utilities within MPS’s
service area, MPS has a nearly exclusive franchise to deliver electric energy
in its service territory. For
additional information on changes to the structure of the electric utility
industry in Maine, see Item 7 below, Management’s Discussion and Analysis of
Financial Condition and Results of Operations, “Overview,” incorporated herein
by this reference. For information on
the competitive conditions facing EA, MAMES and Maricor see also Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of
Operations, “Energy Atlantic Activities,” such information is incorporated in
this section by this reference.
MAMES
and Maricor operate in competitive markets and do not have exclusive
franchises. Competition comes primarily
from other local or regional mechanical and electrical engineering firms, as
well as local, regional or national energy services companies. Public policies related to energy, energy efficiency,
asset lifecycle management, and air emissions may impact the overall
market. The Company has observed that
increasing interest rates generally tend to negatively impact the market for
fee-for-service mechanical and electrical engineering services. However, increasing interest rates also
appear to increase the demand for energy efficiency and asset lifecycle
management services. The Company cannot
warrant or predict these economic effects and makes no predictive statement as
to future market or competitive trends.
Employees
The
information with respect to employees is presented in Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operations,
“Employees,” such information is incorporated in this section by this reference.
Subsidiaries,
Affiliated and Associated Companies
As
stated above, MAM became a holding company effective June 30, 2003. All 1,574,582 shares of MPS common stock
were converted on the books on that date into an equal number of MAM common
stock, which are listed and traded on the AMEX. MAM owns 100% of the common stock of MPS.
MPS
owns 100% of the common stock of Me&NB.
Me&NB owned and operated the Tinker hydro-electric station located
in the Province of New Brunswick, Canada, prior to its sale on June 8, 1999,
and has not conducted active business since the sale.
On
August 24, 1998, the MPUC approved the formation of what was then MPS’s
unregulated subsidiary, 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 began retail
sales activity on March 1, 2000, the date retail electric competition commenced
in Maine. As a start-up unregulated
subsidiary, the MPS Board of Directors and the MPUC limited MPS’s capital
contributions to a maximum of $2 million, subsequently amended to $2.5 million
during 2002. With the formation of MAM,
MPS’s interest in EA was transferred to the new holding company. EA is currently an inactive subsidiary of
MAM.
MPS
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.
For further information regarding Maine Yankee and its decommissioning
progress, see Item 7 below, Management’s Discussion and Analysis of Financial
Condition and Results of Operations, “Maine Yankee,” such information is
incorporated in this section by this reference.
MPS
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
(“NEPOOL”).
Page 13
of 95
In
November 2003, MAM formed MAMES in the United States, now dba “The Maricor
Group,” and MAMES’ Canadian subsidiary, Maricor. MAM owns 100% of the stock in MAMES. MAMES has a 100% ownership interest in Maricor. In December 2003, Maricor acquired Eastcan
Consultants, Inc., which is a regional mechanical and electrical engineering
firm headquartered in Moncton, New Brunswick, Canada with an office in St. John,
New Brunswick, Canada. Eastcan is
currently an operating division of Maricor. An organizational diagram
illustrating the various corporate relationships described in this section is
provided above in Part 1, Item 1, Business, “General” and is incorporated in
this section by this reference.
Company Financial Information
The
public may read and copy any materials the Company files with the SEC at the
SEC’s Public Reference Room at 450 Fifth Street, N.W. Washington, D.C. 20549.
The public may obtain information on the operation of the Public
Reference Room by calling the SEC at 1-800-SEC-0330.
The
Company is an electronic filer and the SEC maintains an Internet site that
contains reports, proxy and information statements, and other information
regarding issuers that file electronically with the SEC at
http://www.sec.gov. The Company also
maintains an Internet site containing such reports at
www.maineandmaritimes.com. All such
reports, including annual reports on Form 10-K, quarterly reports on Form 10-Q,
and current reports on Form 8-K, may be downloaded from such site without
charge. Also listed at the Company’s
site under Investor Relations, Corporate Governance, is the Code of Ethics for
Senior Financial Officers and all other Principal Executive Officers and
Managers, as well as the Company’s policy regarding Insider Trading and
Dissemination of Inside Information.
Item 2. Properties
As
of December 31, 2003, MPS had approximately 380 circuit miles of transmission
lines and MPS owned approximately 1,730 miles of distribution lines, all in
Aroostook County and a portion of Penobscot County in northern Maine. There are no material physical assets held,
owned or controlled by any of the Company’s other subsidiaries.
Substantially
all of the properties owned by MPS are subject to the liens of the First and
Second Mortgage Indentures and Deeds of Trust.
In
response to a Maine environmental regulation to phase out Poly Chlorinated
Bi-phenol (“PCB”) transformers, MPS has implemented a program to eliminate
transformers on its system that do not meet the new state environmental
guidelines. The program will test the
almost 13,000 distribution transformers over a ten-year period. In addition, transformers that pass the
inspection criteria will be refurbished and refitted with lightning arrestors
and animal guards. The initial cost of
the ten-year program was estimated to be $5 million. After three years, MPS has spent approximately $1,033,000 under
the program. MPS is currently in its
fourth year of this ten-year program.
System
Security and Reliability
During
2002, the engineering consulting firm of R.W. Beck, Inc. (“R.W. Beck”), was
retained to undertake a comprehensive facilities evaluation and engineering
audit of the MPS transmission and distribution systems. The purpose of the evaluation and audit were
to provide a comprehensive condition baseline of the transmission and
distribution systems as a beginning basis for development of new transmission
and distribution system plans and the implementation of asset management
initiatives. As a result of the
condition baseline and increasing focus on system planning, MPS has implemented
a continuous in-the-field inspection program for transmission and distribution. The inspection program has been facilitated
by the investment in new mobile equipment allowing for “top down” inspections
versus traditional pole climbing or “bottom up” processes. Further, MPS has begun development of
twenty-year distribution and transmission planning processes. These planning processes are intended to
focus on means to improve overall system reliability, while minimizing
lifecycle asset management costs and reducing future required capital
expenditures.
From
a transmission perspective, the R.W. Beck audit noted that transmission lines
appeared to be in good condition and reasonably maintained. However, they did note on a relative basis
that certain lines were older, but in good condition with the exception of some
of the oldest wood pole lines and areas where bird (woodpecker) damage is a
problem. Through MPS’s in-the-field
transmission inspection program, structures in need of repair or replacement
are
Page 14
of 95
being
identified and repaired or replaced.
Current plans are to undertake complete inspections of MPS’s
transmission system every two years.
Audits
of the Company’s substations and substation-related business processes were
also undertaken by R.W. Beck. The
overall ratings for substations were lower than desired, due to the fact that
almost half of the distribution substations rely on power transformers that
have exceeded their useful lives or are within five years of exceeding their
useful lives. While certain transformers
are beyond their normal life expectancy, MPS has implemented a comprehensive
testing program to identify problem transformers, implementing preventive
maintenance to extend equipment life expectancies, or replacing such
transformers. As part of the system
planning process, MPS is developing a plan to replace older transformers, which
will focus on consolidating substations where possible, all a part of MPS’s
long-term system planning process.
MPS
had planned to reduce its annual capital expenditures to a level approximately
equal to its rate of depreciation. Due
to MPS’s desire to consolidate facilities and ensure increased system
reliability, management believes that renewal and replacement capital
expenditures for the next two to three years may remain at more recent
historical levels of $4.0 million to $6 million annually. Such expenditure levels do not include the
possible construction of additional transmission as later described.
As
a result of the closure of an on-system generation facility and uncertainty
concerning other merchant and non-merchant generation facilities within the
Maritimes and northern Maine regions, MPS continues to evaluate system
security, particularly from an on-peak generation resource perspective. Through
load-flow analysis and utilization of specific contingency or transmission
outage scenarios, it has been determined that under a single contingency or
outage condition and during peak load situations, a system-wide outage is
possible if at least 50 MW’s of on-system generation are not operating. Additionally, under certain conditions, the
analyses noted that a second contingency or transmission line outage could not
be survived within a thirty-minute time frame when similar conditions existed
after a single contingency. Although
Maine Public Service Company does not have a bulk delivery transmission system
as defined by the Northeastern Power Coordinating Council (“NPCC”), MPS is
using NPCC’s standards for planning criteria.
It should be noted that potential contingencies that were studied
focused on situations that could impact MPS’s transmission and distribution
systems, even though certain transmission assets are located in Canada and are
owned by other companies or organizations.
MPS has contingency plans to mitigate such conditions or events in the
case that a major transmission outage or system outage occurred.
As
a result of internal and external transmission system security studies in the
fall of 2002, a unique risk to the MPS system was identified due to a condition
on an NB Power breaker at the Beechwood 138 kV substation in Canada. The risk was that for a single breaker
malfunction at Beechwood substation, MPS could lose two of its three main
interconnections with NB Power. The
loss of these interconnections, coupled with the uncertainty of on-system
merchant generation levels, required MPS to act to prevent conditions that
could result in an outage.
Consequently, MPS paid NB Power $125,900 in December of 2003, for
installing a series breaker, which eliminated this risk to the MPS transmission
system.
In
order to address system security and reliability needs, MPS is also evaluating
the construction of additional interconnections with NB Power. Such projects, subject to further analysis
and regulatory approvals, would increase available and total transmission
capacities. In addition, MPS is
evaluating the merits of joining a new Independent System Operator (“ISO”) or
Regional Transmission Organization (“RTO”).
At this time it is unclear as to the potential outcome of these
efforts. Further, due to shortages of
peaking generation capacity within the Maritimes region, MPS is evaluating
other non-transmission options to ensure system reliability. Such alternative options may require
legislative or regulatory approvals.
Page 15
of 95
Item 3. Legal
Proceedings
Item 3 (i)
Maine and Maritimes Corporation
(a) Maine Public Utilities Commission, Request for Approval of
Reorganization of MPS Into a Holding Company Structure, Docket No. 2002-676
On
October 31, 2002, MPS filed a request for MPUC approval of the formation of a
Maine-based holding company structure.
Under this structure, MPS, EA, as well as other affiliates or
subsidiaries, the creation of which was anticipated to occur at a later date,
would become subsidiaries of a holding company, HoldCo. In its application, MPS stated that the
corporate restructuring would be accomplished through a “reverse triangular
merger,” similar to the one employed in CMP’s Application for Approval of
Reorganization, of Transactions with Affiliated Interests, and Transfer of
Assets, MPUC Docket No. 97-930.
The
proposed MPS restructuring constituted a reorganization requiring MPUC approval
pursuant to the provisions of 35-A M.R.S.A. § 708. In addition to the proposed reorganization, MPS also requested
the approval of certain stock issuances and affiliated interest transactions.
Specifically,
MPS requested MPUC approval of the following transactions and arrangements:
1. the creation of a corporation (“HoldCo”) that
became the parent company of MPS through its ownership of all outstanding
company stock of MPS;
2. the creation of a corporation (“MergeCo”)
whose only purpose was to facilitate the corporate reorganization and which,
when organized, became a wholly-owned subsidiary of HoldCo and which ceased to
exist, once it had served its purpose;
3. the conversion and exchange of all the
outstanding shares of MPS’s common stock into an equal number of shares of
HoldCo’s common stock (to the degree that the conversion and exchange of MPS
stock to be effected in that transaction was deemed to constitute an issuance
of utility stock within the meaning of 35-A M.R.S.A. §§ 901and 902);
4. the merger of MergeCo into MPS, with MPS as
the surviving corporation, and the resulting conversion of the outstanding
shares of MergeCo common stock into a number of shares of the common stock of
MPS equal to the number of shares of MPS’s common stock outstanding immediately
prior to the share conversion described in item 3 above, which was deemed
issued by MPS for this purpose;
5. the dividend by Maine Public Service of its
limited liability company interests in Energy Atlantic to HoldCo pursuant to
35-A M.R.S.A. §§ 708, 901 and 902;
6. the execution and delivery of the Managerial
and Support Services Agreement and approval of the cost manual submitted in
conjunction therewith pursuant to 35-A M.R.S.A. § 707;
7. the winding up and dissolving of Me&NB at
such future time as MPS might deem appropriate pursuant to 35-A M.R.S.A. § 708;
and,
8. the transfer, after the merger date, (i) of
assets that were not “necessary or useful” within the meaning of Section 1101
of title 35-A, from MPS to any MPS affiliate, and (ii) the transfer of all
other assets from MPS to HoldCo or any non-MPS HoldCo subsidiary in the total
amount of up to $1,000,000 over the three-year period beginning upon the merger
date.
MPS
also requested that the Commission authorize the creation of HoldCo and MergeCo
within thirty days of the date of its filing.
This “interim approval” was for the limited purpose of making necessary
filings with the Securities and Exchange Commission under the Public Utility
Holding Company Act and for executing a registration statement under federal
securities law. As part of this request
for interim approval, MPS also represented that should the Commission have
denied its petition for reorganization, or if for any other reason their
organization did not occur, it would dissolve both HoldCo and MergeCo.
Page 16
of 95
Subsequent
to its filing, MPS received and responded to several requests for information
from the MPUC and the Office of Public Advocate, an intervenor in the
proceeding, and met on several occasions with interested parties. The parties settled all issues in the
proceeding, and entered a signed Stipulation formally approved by the MPUC on
March 26, 2003. The text of the MPUC
Order, Docket No. 2002-676 may be viewed as Exhibit 99(ao) of this Form 10-K
such information is incorporated in this section by this reference. MPS also filed, on March 11, 2003, a Form
S-4 Registration Statement with the Securities and Exchange Commission for
“Maine & Maritimes Corporation” the entity designated as “HoldCo” in this
disclosure. The reorganization became
effective June 30, 2003.
At MPS’s Annual Meeting of
Shareholders, held on May 30, 2003, shareholders of MPS voted to approve its plan to create a
holding company structure, under MAM.
Of the shares eligible to vote, 57.07% voted “For” the holding company
proposal, 10.19% voted “Against,” and 32.74% abstained or were “broker no
votes.” The reorganization was
completed by July 1, 2003. No change in
beneficial ownership resulted from the reorganization, which is described in
more detail in the Form S-4/A of MAM filed with the Commission on April 15,
2003 and is incorporated in this section by this reference. The filing is reviewable on the SEC’s
website at “http://www.sec.gov/edgar” or on the MAM Investor Relations page at
http://www.maineandmaritimes.com/corporate/1373T04_CP.PDF.
Under
the new holding company corporate structure, MPS became a separate subsidiary
of MAM. EA, previously MPS’s
unregulated competitive electricity supply company also became a direct
subsidiary of, MAM. Me&NB, which is
an inactive Canadian company, remained a direct subsidiary of MPS.
Following
the July 1, 2003 completion of the reorganization, shares of MPS common stock
were converted on the books (with no exchange of certificates) into the same
number of shares of common stock of MAM.
The MAM common stock shares are currently traded on the AMEX under the
ticker symbol “MAM.”
Item 3 (ii)
MPS Rate Cases
(a) Maine Public Utilities Commission, Request for Approval of Alternative
Rate Plan, MPUC Docket 2003-85.
As
reported in prior MPS and MAM quarterly reports on Form 10-Q which are
incorporated in this section by this reference, on March 6, 2003, MPS submitted
its formal “Request for Approval of Alternate Rate Plan” (the “ARP”) (MPUC
Docket 2003-85). The proposal was a seven-year rate plan for its distribution
delivery services with a target implementation date on or before July 1, 2003.
The ARP was an alternative form of regulating MPS’s distribution assets,
similar to the performance rate plans the MPUC has adopted for CMP and Bangor
Hydro-Electric Company. In accordance
with a state statute enacted during the course of MPS’s ARP proceedings, Maine
utilities requesting an ARP are required to file cost-of-service financial
information as part of the proceeding.
In connection with this aspect of the ARP review and analysis, MPS had
been authorized by, and had received final approval from the MPUC to increase
its electric delivery rates. Also in connection with this process MPS
announced that effective October 1, 2003, MPS would increase the distribution
component of its electric delivery rate by 6.23% for a total increase in its
electric delivery rate of 3.44%, for a total revenue increase of $940,000. However, during the compliance filing phase
of this proceeding, an issue arose concerning the calculation of rate sheets
and the corresponding retail distribution and transmission revenues. Following the entry of a procedural order, discovery, and a public
conference a Supplemental
Stipulation in this case was entered into and filed with the Maine Public
Utilities Commission (“MPUC”) on October 17, 2003, correcting the allocation of
revenues between distribution and transmission, and resulting in MPS increased its total electric delivery
rate by 3.78%, or a total revenue increase not to exceed $1,126,552. As a result, effective November 1, 2003, MPS
distribution rates were increased. This
increase included $685,037 in distribution revenues and $441,515 in
transmission revenues. A copy of the Stipulation and the Order
approving the increase may be viewed on the MPUC website at
http://www.state.me.us/mpuc/ and is incorporated in this section by this
reference.
Following the
entry of the order approving the Supplemental Stipulation, the ARP proceeding
was bifurcated and on December 29, 2003, MPS notified the MPUC of its intention
to withdraw the remaining elements of the ARP docket. For the purposes of future rate proceedings MPS will continue to
evaluate if an ARP is in the best interest of MPS, its shareholders and
consumers or if it should continue to proceed with cost-of-service rate filings
as it has done in the past.
Page 17
of 95
As
a part of this rate case, the MPUC approved MPS’s request to fix its debt
interest rates through the purchase of interest rate swap derivatives. Prior to MPS’s fixing of its interest rates
through such interest rate swaps, all of its debt had been subject to variable
interest rates. Given the long-term
nature of MPS’s debt, management believed that locking the rates at
historically low levels reduced future shareholder and consumer risks
associated with the volatility of interest rates. Effective interest rates achieved by the swaps for MPS’s variable
rate debt through maturity range from 2.79% to 4.68%. See Item 16(a) of this Form 10-K, Note 8 of the Consolidated
Financial Statements, “Long-Term Debt” for a description of these debt issues
and associated swap rates.
(b) Maine Public Utilities Commission Investigation into MPS’s Stranded
Cost Revenue Requirements
and Rates in MPUC Docket No.2003-666.
As
previously reported in the prior MPS 8-K filing of March 2, 2004, MPS received
final approval from the MPUC for the stranded cost revenue component of its
electric delivery rates. Under Title 35-A of the Maine Revised Statutes
Annotated, Section 3208, the MPUC is required to periodically investigate and
adjust the stranded cost charges reflected in the rates of a transmission and
distribution utility. In accordance with this provision, on September 16,
2003, in Docket No. 2003-666, the MPUC issued a notice of investigation in
order to determine whether MPS’s rates must be changed effective March 1, 2004
to reflect any changes in MPS’s stranded costs. On February 27, 2004, the
MPUC issued an order approving a stipulation under which MPS is allowed to
recover $11,785,339 per year to satisfy its approved stranded cost revenue
requirements for the “rate effective period,” which began March 1, 2004, and
will end on December 31, 2006. The
approved revenue requirement for the rate effective period ended February 29,
2004 was $11,540,000. Under the
approved stipulation MPS’s stranded cost rates approved in Docket No. 2003-85
will remain in effect during the rate effective period. The
stipulation approved by the MPUC in Docket No. 2003-666 also approved and
reaffirmed each of the elements and associated balances of MPS’s recoverable
stranded costs.
As explained more fully
below, during the course of Docket No. 2003-666 the parties reviewed the manner
in which MPS was recovering and accounting for its carrying charges associated
with the deferred fuel element of its stranded cost. As a result of the stipulation approved in Docket No. 2003-666,
MPS will record deferred income tax expense associated with deferred fuel
carrying charges during the rate effective period from March 1, 2004 through
December 31, 2006, as compared to past treatment where such expense was
deferred for future recovery. Because
the deferred fuel carrying charge component of MPS’s stranded costs is not
expected to be fully amortized until 2012, MPS anticipates that deferred income
tax expense will be incurred through 2012, subject to future stranded cost
filings with the MPUC. In Dockets Nos.
98-577 and 2001-240, the parties stipulated that MPS would accrue carrying
costs on its unrecovered fuel balance (the “deferred fuel account”) during the
respective rate effective period at its net of tax cost of capital rate.
Consistent with the stipulation in Docket No. 2001-240, MPS accrued a carrying
charge using the net of tax rate of 7.98% through October 31, 2003 applied
against its unrecovered deferred fuel balance. From November 1, 2003 to
December 31, 2003 MPS accrued its carrying charge using a net of tax rate of 7.06%,
based on the cost of capital approved in Docket No. 2003-85 (described in
Docket No. 2003-85 Partial Stipulation filed on September 2, 2003).
During the course of the
Docket No. 2003-666 proceeding, MPS determined that it had not previously
recognized accumulated deferred income taxes with respect to the carrying
charges on the deferred fuel account and that the recording of a deferred tax
liability on its balance sheet pursuant to FAS 109 in the amount of $2.896
million was required. The deferred fuel balance as of March 1, 2004 prior to
any adjustment was $18,838,000. Under
the stipulation MPS is allowed to adjust its accumulated deferred income tax
account and the deferred fuel balance by $2,896,000, as of March 1, 2004,
resulting in a total deferred balance as of March 1, 2004 of $21,734,000.
Under the approved stipulation the parties also agreed that the return
component on the deferred fuel balance should be reduced in such a manner that
ratepayers were held harmless on a net present value basis as a result of the
March 1, 2004 adjustment to the deferred fuel balance. During the rate
effective period ending on December 31, 2006, the overall pre-tax return
component on the deferred fuel balance will be 8.28%, reflecting a 6.17% return
on equity. The return on the deferred fuel balance will be reviewed in
future stranded cost rate setting proceedings and will be adjusted as necessary
in order that the present value of the revenue requirements of the deferred
fuel account without the adjustments described above equals the present value
of the revenue requirements of the deferred fuel account with the
adjustments. MPS concludes that as a result of this stipulation and the
foregoing described adjustment to the deferred fuel balance and the accumulated
deferred income tax liability that no further adjustment is necessary under FAS
109 in order to reflect prior unrecorded deferred income taxes.
Page 18
of 95
The
decreased cost of capital rate beginning on March 1, 2004 will have an impact
on future stranded cost earnings and stranded cost freed-up cash flows, but
will not impact future distribution or transmission earnings. In the year
2004, MPS anticipates that it will record deferred income tax expense of
approximately $412,000 associated with the deferred fuel carrying charges. The amount of deferred income tax expense
recorded in future years will vary depending upon the amount of the accrued
carrying charge in any year, and the tax rates then in effect. MPS anticipates that earnings from carrying
charges on its stranded costs in 2004 will be approximately $267,000 lower than
the amount that would have been recorded had MPS continued to use the original
cost of capital on its deferred fuel balance, for a total earnings impact of
$679,000 in 2004. The impact on future
earnings resulting from the agreed upon lower cost of capital, when compared
against the cost of capital used in prior stranded cost filings, will vary. Schedules filed by MPS as part of the stipulation in Docket No.
2003-666 reflect the deferred fuel balance as of March 1, 2003, certain
additions relating to the Wheelabrator-Sherman above-market contract through
December 2006, and the amortization of the deferred fuel balance though 2012. Applying these assumptions, current tax
rates and the agreed upon cost of capital, MPS anticipates that the impact on
future earnings resulting from recording deferred income taxes on accrued
carrying charges and applying a lower cost of capital to the deferred fuel
balance could range from $1.0 million in 2005, increasing to $1.2 million in
2007, then gradually decreasing to $17,000 in 2012. These amounts may vary with changes in the deferred fuel balance
and other variables which MPS cannot predict with certainty at this time. Management is analyzing means to mitigate
the impact of this stipulation on future net income and stranded cost freed-up
cash flows.
In
addition to the return allowed on its deferred fuel account as set forth above,
under the approved stipulation MPS shall be allowed to recover the following
pre-tax returns on the applicable stranded cost rate base components during the
rate effective period: (i) the pre-tax return on unrecovered balance of the
Wheelabrator-Sherman NUG Contract Buydown shall be 2.79% plus its FAME issuance
costs; (ii) the pre-tax return on the unrecovered Seabrook Investment and
approved special rate contract costs shall be 11.74%; and, (iii) the pre-tax
return on the Maine Yankee decommissioning related costs shall be 8.56%. The stipulation and any accompanying
exhibits can be found on the MPUC website at www.maine.gov.us/mpuc and are
incorporated in this section by this reference.
(c) Federal Energy Regulatory Commission Approval
of Wholesale Transmission Rates, FERC Docket No. ER00-1053
The
FERC approved MPS wholesale transmission rates effective June 1, 2002, in FERC
Docket No. ER00-1053, a proceeding related to MPS’s Open Access Transmission
Tariff (“OATT”) discussed below. On
August 6, 2002, MPS notified the MPUC of its intention to implement the
associated transmission component of its retail transmission and distribution
(“T&D”) rates, with the new rates effective October 1, 2002. The FERC maintains jurisdiction over all
transmission rates. This implementation
increased overall delivery rates by approximately 2%. MPS increased its transmission rates subject to refund and
issuance of a final order by FERC, which was issued in March, 2003.
(d) Federal Energy Regulatory Commission 2003 Open Access Transmission
Tariff Formula Rate filing, FERC
Docket ER00-1053-009
As
previously reported in prior MPS quarterly reports on Form 10-Q which is
incorporated in this section by this reference, pursuant to Section 2.4 of the
Settlement Agreement filed on September 30, 2000, in Docket No. ER00-1053-000,
and accepted by the FERC on September 15, 2000, MPS provided parties and FERC
staff on June 10, 2003 the changed Open Access Transmission Tariff (“OATT”)
Formula Rate charges that MPS proposed to apply on June 1, 2003 together with
back-up materials. On June 1, 2003 the Formula Rate charges became effective
subject to a refund that may occur in connection with a settlement stipulation
currently being negotiated by the parties to the proceeding. The initial notification
for the 2003 filing was filed with the FERC on March 31, 2003. In its 2003 OATT filing, MPS provided the
proposed changes to its OATT Formula Rate to the intervening parties and FERC
staff. In general, MPS sought a slight
modification to its rate formula under its transmission tariff. On February 11, 2004, following discussions
to resolve all outstanding issues in the 2003 informational filing, MPS, the
parties, FERC Trial Staff, and the MPUC reached
a settlement agreement (the “Settlement Agreement”) regarding changes to the
MPS Formula Rate. The Settlement
Agreement and OATT revisions filed reflect and set forth the agreement
reached. Specifically, the parties and
the FERC Trial Staff agreed to certain provisions and changes to MPS’s Formula
Rate and OATT as summarized below and in the revised MPS OATT pages. The revised MPS OATT pages in redline and
non-redline format are included in Attachment A to the Settlement Agreement. The provisions and changes agreed to are
summarized as follows:
Page 19
of 95
• A fixed 11% return on common equity shall
continue to be used. The formula makes
clear that the return on common equity may not be changed unless pursuant to
section 205 or 206 of Federal Power Act, 16 U.S.C. §§ 824d, 824e.
• In calculating the weighted overall return,
MPS’s actual long term debt and preferred costs will be calculated as specified
in Note 1 of Statement AV of the Formula Rate.
For the three years ending June 1, 2006, MPS’s equity ratio will be (1)
the actual equity ratio as calculated according to Formula Rate Statement AV or
(2) 53%, whichever is lower, and MPS’s debt ratio will be (a) the actual debt
ratio as calculated according to Formula Rate Statement AV or (b) 100% less 53%
less the actual preferred stock ratio, whichever is higher.
• Effective January 1, 2004, MPS will begin
booking depreciation accruals for the certain plant accounts at the rates
specified, and depreciation expense reflecting these rates will be included in
the MPS Formula Rate be used in the OATT charges to be effective June 1, 2005.
Formula Rate Statement AJ makes clear that the depreciation rates may not be
changed unless pursuant to section 205 or 206 of Federal Power Act, 16 U.S.C.
§§ 824d, 824e.
• Depreciation rates for certain plant accounts
will be effective January 1, 2003 and depreciation expense reflecting accruals
at these rates and will be included in the MPS Formula Rate and will be used in
the OATT charges to be effective June 1, 2004. Formula Rate Statement AJ makes
clear that the depreciation rates may not be changed unless pursuant to section
205 or 206 of Federal Power Act, 16 U.S.C. §§ 824d, 824e. Also the
proposed amounts of depreciation accrual previously recorded through December 31,
2002 and related to Account 350.2 and 350.3 will not be reversed and will
continue to be recognized as credits to rate base.
• MPS will continue to include intangible plant
in rate base, and in addition, MPS will reduce intangible plant by accumulated amortization
(reflected on Formula Rate Statement AE) and include an amortization of
intangible plant in the calculation of depreciation and amortization
expense. Formula Rate Statement AJ
shall be modified to include the intangible amortization in total general plant
depreciation and intangible amortization.
The transmission labor allocator shall be used to allocate total general
plant depreciation and intangible amortization to the transmission function. MPS will use a three-year amortization
period for computer hardware and software related intangible plant, except that
extraordinary software investment that on a project basis exceed $100,000 shall
be amortized over seven years, with appropriate recognition of deferred taxes. In the informational filing MPS makes each
year pursuant to Section 2.4 of the Settlement Agreement, MPS will include
worksheets that detail the following information regarding projects being
amortized in Account 303: a description of the project, beginning and ending
balances, the annual amortization and total accumulated amortization for that
project. A sample worksheet is included
in Attachment B of the Settlement Agreement.
• MPS will allocate external regulatory
expenses to all customers based on a load ratio share basis beginning with test
year 2002 expenses. The current
three-year amortization will continue.
A conforming change to Formula Rate Schedule 1b will be made.
• A revenue credit for rents in Account 454
(pole attachments, etc.) shall be added to the Formula Rate Statement AU. A conforming change to Formula Rate Schedule
2 will be made.
• MPS will add a new line item to Schedule 2 of
the Formula Rate to reduce rate base for deferred directors’ fees. The amount of directors’ fees to be shown on
Schedule 2 of the Formula Rate will be developed on Formula Rate Statement AD2.
• MPS will modify the Formula Rate Statement
AF2 to reduce rate base by the net of amounts in Account 228.3 (i.e. Accounts
228.310, 228.320, and 228.330) minus the amount in Account 186.991. MPS will average the beginning and end of
year balances in the accounts and allocate the net of the averages to the
transmission function using the transmission labor allocator. Formula Rate Schedule 2 will be modified to
add a line item for pensions and benefits.
Page 20
of 95
• All costs: (1) of generation, (2) of entering
the generation business and (3) of any other non-transmission business
(regulated or non-regulated) activities – including all deferred income taxes
and an appropriate allocation of administrative and general expenses – shall be
excluded from the transmission rate.
Any costs of starting or operating any business other than transmission
or distribution that have or will be incurred as of January 1, 2003 shall be
separately identified and segregated so that transmission customers can review
those costs. MPS will maintain
sufficient records to enable customers to monitor these costs and to ensure that
these costs are identified and not charged to transmission customers, and to
enable MPS to support and explain its allocation of costs. Any information provided by MPS regarding
these costs will be treated as supporting documentation under Section 2.3 of
the Settlement Agreement and any disputes concerning that information will be
resolved under the terms of Section 2.3 and not Section 2.4.
• In the informational filing MPS makes each
year pursuant to Section 2.4 of the Settlement Agreement, MPS will include
worksheets that detail the treatment of deferred taxes related to Accelerated
Costs Recovery System (“ACRS”) / Modified Accelerated Cost Recovery System
(“MACRS”) property. Specifically, MPS
will demonstrate by journal or account entries that the tax benefits related to
the tax deductions for the retirement of ACRS/MACRS property and for costs of
removal of that property were credited to Account 282 or 283. A sample worksheet is included in Attachment
B of the Settlement Agreement.
• For retail transmission charges, MPS changed
the retail transmission rates each year on October 1. Specifically, MPS will add the following language to the Formula
Rate Schedule 1.1.1: “Retail transmission price changes will take effect on
October 1. The transmission revenue
effect of any difference (positive or negative) between when transmission price
changes would normally occur (June 1) and when they actually occur (October 1)
will be accrued with interest, calculated pursuant to Section 35.19a for FERC’s
regulations and included in the next determination of transmission prices for
retail transmission customers.” Certain clean-up edits to the Formula Rate were
also made.
MPS
will also modify OATT Schedule 2, Reactive Support and Voltage Control from
Generation Sources Service to specify the allocation of reactive support
costs. MPS will allocate reactive
support charges on a load ratio share basis.
For wholesale customers, charges for reactive support shall occur each
month on an as billed basis. For retail
customers, the reactive support charges shall be rolled into the retail
transmission revenue requirement on a prospective yearly basis with a true-up
the next year. This change to Schedule
2 was effective April 1, 2003. MPS also
will add Schedule 4 to the Formula Rate to describe the allocation of reactive
support costs and modify Schedule 1.1.2 to reflect the allocation for retail
transmission customers.
The
parties also agreed that if there is a conflict between the Formula Rate and
OATT, changes listed in Section 2.2 of the Settlement Agreement and changes
reflected on the Formula Rate and OATT pages included in Attachment A to the
Settlement Agreement will control.
Consistent
with the 2000 Settlement Agreement, the parties also agreed that before each
annual (June 1) adjustment under MPS’s Formula Rate, MPS shall provide the
Parties and Commission Trial Staff with the changed charges that MPS proposes
to apply on June 1 together with back-up materials. MPS will use its best efforts to provide that information by May
15 of each year. MPS will submit an informational filing with the Commission
setting forth the changed charges by June 15 of each year. If a party to the
Settlement Agreement disputes the annual charge change, that party will possess
the right to raise any issue with the Commission (even after June 15). MPS will respond to reasonable requests for
supporting documentation requested by any party or FERC Trial Staff (even after
June 15).
The
parties also agreed that by March 1, 2006, MPS will meet with the parties and
FERC Trial Staff to determine if any of the parties or FERC Trial Staff believe
that the Formula Rate does not produce reasonable results. If MPS and the parties and FERC Trial Staff
are unable to reach agreement, then MPS will submit by April 30, 2006, under
section 205 of the Federal Power Act, 16 U.S.C. § 824d, a unilateral
filing with FERC restating or revising the Formula Rate.
Page 21 of 95
As
a result of the settlement, MPS will rebill OATT customers for charges under
the OATT related to the implementation of the Rate Formula changes effective
June 1, 2003. The rebilling shall
include interest computed under 18 C.F.R. § 35.19a. For the purpose of keeping the total retail
transmission and distribution rate constant until the October 1, 2004, MPS will
not rebill the retail transmission customers until October 1, 2004. At the time of the retail transmission
rebilling, MPS will include refunds with interest pursuant to 18 C.F.R.
§ 35.19a for the rebilling and any appropriate surcharges with interest
calculated pursuant to FERC regulations, 18 C.F.R. § 35.19a, associated
with the delay in implementation of the 2003 retail transmission change in
charges from June 1, 2003 to October 1, 2003.
Also included in the rebilling will be the yet unbilled refunds and
surcharges associated with past periods, including but not limited to those
associated with the delay in implementation of the 2002 retail transmission
change in charges from June 1, 2002 to October 1, 2002, and the 2003 retail
transmission change in charges from June 1, 2003 to November 1, 2003, and
refunds associated with the settlement filed on March 7, 2003 in Docket No.
ER03-1053-008.
MPS
has requested among other things that the FERC accept the 2003 informational
filing and the proposed OATT revisions.
On February 17, 2004 FERC issued its Notice of Filing and established a
public comment date deadline of March 3, 2004.
The matter has been briefed to the Commissioners who had no objections
to any provisions of the MPS filing. An
order approving the 2003 informational filing and OATT revisions is expected
during the first quarter of 2004. The
Settlement Agreement, cover correspondence and its attachments are submitted
with this filing as Exhibit 99(aq), and are incorporated in this section by
this reference.
Item 3(iii)
Other MPS Matters:
(a) Maine Public Utilities Commission Notices of Inquiry, MPUC Dockets No.
2003-82; 2003-423.
On
February 11, 2003, the MPUC initiated a formal Notice of Inquiry (“NOI”) into
the status of the competitive market for electricity supply in northern Maine
(MPUC Docket No. 2003-82). The NOI is
not directed at MPS or any specific party or entity but is a general inquiry
designed to gather information about the adequacy of existing market
structures, rules and laws in light of the limited number of supplier/generator
participants in the region. The MPUC’s
inquiry is for the purpose of identifying potential concerns related to
northern Maine’s supply and market situation, and to explore possible
solutions. In contrast to the rest of
Maine, which is part of the Independent System Operator – New England
(“ISO-NE”) region, northern Maine and MPS are electrically interconnected to
the Canadian Maritimes region, which also includes the electric loads and
generation of New Brunswick, as well as Nova Scotia and Prince Edward
Island. Load and generation in northern
Maine, which comprises MPS’s service territory, are interconnected to the rest
of Maine and New England only by transmission through New Brunswick. The Northern Maine Independent System
Administrator (“NMISA”) operates the bulk power and transmission systems for
the region. The divestiture of generation
assets in connection with the Maine Electric Industry Restructuring Act eliminated
rate regulation for the production and sale of electricity supply as of March
1, 2000. During the subsequent period
of time, the retail and wholesale markets have experienced a limited number of
participants. In furtherance of the
MPUC’s inquiry, it requested comments on a number of issues related to these
unique market conditions. MPS has
provided comments for the MPUC’s consideration. There have been no other material or further developments in this
proceeding during 2003. At this time MPS cannot predict the nature or the
outcome of any finding, decision or ruling by the MPUC in this proceeding.
On
June 18 2003, the MPUC also initiated a similar Notice of Inquiry and Request
for Comments concerning “Incentives to Promote Energy Efficiency and Security
of the Electric Grid” (MPUC Docket No. 2003-423). MPS provided comments to the MPUC on July 7, 2003. There have been no other material or further
developments in this proceeding during 2003.
At this time the Company cannot predict the nature or the outcome of any
finding, decision or ruling by the MPUC in this proceeding.
(b) Wholesale Standard
Offer – MPUC Docket No. 2003-677 and Sale of Capacity and Energy Available from
Wheelabrator-Sherman Energy Company.
As
previously reported in prior MPS Form 8-K reports, on September 16, 2003, the
MPUC issued an Order Regarding Standard Offer Provider For Maine Public Service
Company (Docket No. 2003-670) to resolve all issues regarding the upcoming
standard offer solicitation for all customer classes in MPS’s service
territory. Pursuant to Maine’s Electric
Restructuring Act, the MPUC administers periodic bid processes to select
providers of SOS. The current SOS
provider arrangement for all three sets of customer classes in MPS’s service
territory terminated on
Page 22
of 95
February
29, 2004. Accordingly, the MPUC
solicited bids for MPS SOS customers beginning on March 1, 2004. WPS ESI was awarded the Standard Offer for
all customer classes for the period March 1, 2004 through February 28, 2006, as
well as the entitlement to capacity and energy from Wheelabrator-Sherman
(“WS”), located in Sherman, Maine, for the term beginning at the hour ending on
1:00 p.m. on March 1, 2004 through the expiration of the Wheelabrator-Sherman
NUG Contract in December 2006. The bid
solicitation can be viewed at http://www.mainepublicservice.com.
(c) WPS Canada
Generation, Inc. – FERC Docket Nos. ER03-689-000, et al.; and WPS Canada
Generation, Inc. FERC Docket No.ER-04-210-000; WPS Reactive Power Service Rate
(“RPS”) matter.
On
April 1, 2003, as amended on April 8, 2003, WPS Canada filed rate schedules for
MPS and the NMISA, Rate Schedule FERC Nos. 2 and 3, respectively to obtain
$142,734 per year in compensation for WPS’s RPS service. Parties, including MPS intervened and/or
protested the WPS RPS rate case. While this charge has no direct effect on MPS
or the Company’s shareholders, MPS and other parties intervening in the matter,
believed that the charge sought by WPS Canada Generation, Inc. (“WPS”) was not
justified and therefore contested the issue.
By order issued May 19, 2003, the FERC accepted the RPS rate schedules
for filing, established that rate schedules would become effective on April 2,
2003, subject to refund, provided for a hearing, held the hearing in abeyance
and established settlement procedures.
On July 29, 2003, the Chief Judge ordered the termination of the
settlement procedures and ordered the institution of “Track II” hearing
procedures. Direct and rebuttal
testimony was submitted. MPS filed its
testimony on this case on October 17, 2003.
MPS also, as a precautionary measure, included the pass-through of this
charge in its settlement proposal in its FERC OATT case described above, in the
event that WPS was successful in obtaining FERC approval for this charge. A settlement in principal was reached prior
to the commencement of the actual hearing in the matter. The parties finalized a settlement in the
matter resolving all outstanding issues in the above referenced dockets and on
February 10, 2004 the settlement agreement, its appendices, an “Explanatory
Statement in Support of the Settlement,” and redlined rate sheets were filed
with the FERC Presiding Administrative Law Judge.
(d) Maine Public Utilities Commission, Application for Exemption of Chapter
304 (MPUC Docket No. 2003-122).
On
February 21, 2003 the Company filed with the MPUC an “Application for Exemption
of Chapter 304” (MPUC Docket No. 2003-122). In connection with MPS’s
reorganization (discussed in Item 3 (i) (a) above) and EA’s withdrawal from
retail electricity markets in northern Maine, MPS filed with the MPUC on
February 21, 2003, an “Application for Exemption of Chapter 304” to exempt MPS
and EA from certain management restrictions.
These restrictions had been imposed to allow EA to engage in energy
marketing activities within MPS’s service territory. A series of settlement conferences were held between the MPUC
Advisory Staff, the Office of the Public Advocate, WPS Energy Services, Inc.
and MPS. On June 24, 2003, the parties submitted a Stipulation to the
MPUC. The MPUC issued an Order
Approving Stipulation in this matter on July 24, 2003, which approved a partial
waiver of the requirements of Chapter 304 (the “304 Order”) and resolved all
issues in this matter. Under the
provisions of the 304 Order, MPS is exempted from the employee sharing
provisions of Chapter 304 of the Commissions Rules subject to certain specified
conditions. The exemptions and waivers
granted in the 304 Order are expressly contingent on the condition that EA
cease marketing in MPS’s service territory effective March 1, 2003. The 304 Order also provides that the parties
to the proceeding may revisit the matter in the event EA should subsequently
choose to re-enter the northern Maine retail electricity market in the
future. In connection with its
announced intent to withdraw from the retail electricity markets in northern
Maine EA has ceased all of its energy marketing activities in MPS’ service
territory effective March 1, 2003, as well as the balance of the State. A copy of the Stipulation and the 304 Order
approving the stipulation may be viewed on the MPUC website at
http://www.state.me.us/mpuc/.
(e) Settlement of Maine Yankee Litigation.
As
has been previously reported by the Company in its 8-K and 10-Q quarterly
reports, in May 2000, Maine Yankee terminated its decommissioning operations
contract with Stone & Webster Engineering Corp. (“Stone & Webster”)
pursuant to the terms of the contract.
Stone & Webster disputed Maine Yankee’s grounds for the
termination. In June 2000, Stone &
Webster filed a voluntary petition under Chapter 11 of the United States
Bankruptcy Code with the United States Bankruptcy Court for the District of
Delaware. As a result of the Bankruptcy
Court approving the Third Amended Plan of Reorganization in the Stone and
Webster Bankruptcy, all litigation between Maine Yankee and the bankruptcy
estate was settled. In connection with
this settlement, Maine Yankee also withdrew its complaint against Envirocare,
Inc. in Federal District Court. See
Part II, Item 7 below, for a more detailed discussion of Maine Yankee.
Page 23
of 95
Item 4. Submission
of Matters to a Vote of Security Holders
At
the 2003 Annual Meeting of Stockholders of MPS held on May 30, 2003, two
matters were voted upon. First was the
uncontested election of Robert E. Anderson, Michael W. Caron, and Nathan L.
Grass for terms ending in 2006, and David N. Felch for a term ending in 2004;
each was elected.
Second
was the approval of the agreement and plan of merger and reorganization to
create a holding company structure under Maine & Maritimes Corporation,
with the following recorded vote:
|
|
|
For
|
|
Against
|
|
Non-Votes
and
Abstentions
|
|
|
Approval of the Agreement and Plan of
Merger and Reorganization
|
|
898,535
|
|
160,464
|
|
515,323
|
|
Of
the total shares eligible to vote, 57.07% voted in favor of the proposal.
Page 24
of 95
PART II
Item 5. Market for
Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Maine
& Maritimes Corporation became a holding company effective June 30,
2003. All 1,574,582 shares of MPS
common stock were converted on that date into an equal number of MAM common
stock, which are listed and traded on the AMEX under the trading symbol
“MAM.” As of December 31, 2003, there
were 890 holders of record of the Company’s common stock, with 1,580,512 shares
outstanding. As of December 31, 2002,
common stock shares outstanding for MPS were 1,574,115.
Dividend
data and market price related to the common stock are tabulated as follows for
the two most recent calendar years:
|
|
|
Market
Price
|
|
Dividends
|
|
|
|
|
High
|
|
Low
|
|
Paid Per
Share
|
|
Declared
Per Share
|
|
|
2003
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
32.26
|
|
$
|
24.99
|
|
$
|
.37
|
|
$
|
.37
|
|
|
Second Quarter
|
|
$
|
32.95
|
|
$
|
26.36
|
|
.37
|
|
.37
|
|
|
Third Quarter
|
|
$
|
36.90
|
|
$
|
31.60
|
|
.37
|
|
.37
|
|
|
Fourth Quarter
|
|
$
|
35.95
|
|
$
|
34.37
|
|
.37
|
|
.38
|
|
|
Total Dividends
|
|
|
|
|
|
$
|
1.48
|
|
$
|
1.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
30.48
|
|
$
|
28.75
|
|
$
|
.35
|
|
$
|
.35
|
|
|
Second Quarter
|
|
$
|
30.55
|
|
$
|
29.50
|
|
.35
|
|
.35
|
|
|
Third Quarter
|
|
$
|
29.84
|
|
$
|
25.60
|
|
.35
|
|
.37
|
|
|
Fourth Quarter
|
|
$
|
34.59
|
|
$
|
24.25
|
|
.37
|
|
.37
|
|
|
Total Dividends
|
|
|
|
|
|
$
|
1.42
|
|
$
|
1.44
|
|
Dividends
declared within the quarter are paid on the first day of the succeeding
quarter.
The
Company has determined that the common stock dividends paid in 2003 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.
Securities
Authorized for Issuance Under Equity Compensation Plans
|
Plan Category
|
|
Number of
securities
to be issued upon
exercise of
outstanding options,
warrants and rights
|
|
Weighted-average
exercise price of
outstanding options,
warrants and rights
|
|
Number of
securities remaining
available for future issuance
under equity compensation
plans
(excluding securities reflected in
column (a)
|
|
|
|
|
(a)
|
|
(b)
|
|
(c)
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plan approved by
security holders
|
|
10,500
|
|
31.48
|
|
139,500
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plan approved by
security holders
|
|
0
|
|
n/a
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
10,500
|
|
31.48
|
|
139,500
|
|
Page 25
of 95
Sale of Unregistered Securities
On
December 1, 2003, the Company issued 5,529 shares of its common stock in
connection with the acquisition by its Canadian subsidiary, Maricor Ltd, of all
of the outstanding common shares of Eastcan Consultants, Inc., a closely held
Canadian corporation. No underwriter
was used. The persons who acquired the
securities were Michael C. Gillis, Malcolm A. MacLellan, Richard Keirstead,
Stephen Erb, and Scott Mowery. The
consideration is stated in Item 16(a) to this Form 10-K, Note 14 to the
Consolidated Financial Statements, “Acquisitions.” The securities were issued under the exemption provided by
Section 4(2) of the Securities Act of 1933 as a transaction by an issuer not
involving a public offering.
Item 6. Selected
Financial Data
A
five-year summary of selected financial data (1999-2003) is as follows:
Five-Year
Summary of Selected Financial Data
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
Income Statement Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (1)
|
|
$
|
37,860,509
|
|
$
|
44,104,133
|
|
$
|
49,698,040
|
|
$
|
78,238,279
|
|
$
|
67,456,117
|
|
|
Net Income Available for Common Stock
|
|
$
|
2,805,601
|
|
$
|
6,543,421
|
|
$
|
5,236,527
|
|
$
|
5,300,632
|
|
$
|
4,005,556
|
|
|
Basic and Diluted Net Income Per Share of
Common Stock
|
|
$
|
1.78
|
|
$
|
4.16
|
|
$
|
3.33
|
|
$
|
3.34
|
|
$
|
2.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets (2)
|
|
$
|
141,268,765
|
|
$
|
141,986,156
|
|
$
|
143,334,943
|
|
$
|
150,856,876
|
|
$
|
171,548,480
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt Outstanding
|
|
$
|
30,680,000
|
|
$
|
33,765,000
|
|
$
|
34,940,000
|
|
$
|
35,990,000
|
|
$
|
42,015,000
|
|
|
Less amount due within one year
|
|
1,450,000
|
|
3,085,000
|
|
1,175,000
|
|
1,050,000
|
|
25,000
|
|
|
Long-Term Debt
|
|
29,230,000
|
|
30,680,000
|
|
33,765,000
|
|
34,940,000
|
|
41,990,000
|
|
|
Common Shareholders’ Equity
|
|
46,984,490
|
|
47,029,071
|
|
42,731,149
|
|
39,585,951
|
|
37,159,608
|
|
|
Total Capitalization
|
|
$
|
76,214,490
|
|
$
|
77,709,071
|
|
$
|
76,496,149
|
|
$
|
74,525,951
|
|
$
|
79,149,608
|
|
(1) Electric
restructuring in Maine began on March 1, 2000, with MPS providing only
transmission and distribution (“T&D”) or delivery services subsequent to
that date. Prior to March 1, 2000, MPS
provided electric power to its customers by operating its own generating
facilities, principally located in Canada, or by purchasing power. The MPUC allowed the recovery of stranded
costs from our customers, beginning March 1, 2000. MPS’s sales in MWH’s are comparable to pre-March 1, 2000
sales. Financial results for periods
before March 1, 2000, reflect revenues and associated expenses for delivery
charges and electric power provided to our customers. After March 1, 2000, MPS’s revenues do not reflect revenues
associated with electric power. After
considering the differences above, comparisons of financial results for periods
prior to March 1, 2000, to periods after that date are difficult and the
Company makes no conclusion or statement with respect to such comparisons.
(2) For
2003 and 2002, total assets reflects the reclassification of accrued removal
obligations as a liability from accumulated depreciation.
See
Item 7a, “Quantitative and Quantitative Disclosures about Market Risk,”
incorporated in this section by this reference, concerning material risks and
uncertainties which could cause the data reflected herein not to be indicative
of the Company’s future financial condition or results of operations.
Page 26
of 95
Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations
This
Management’s Discussion and Analysis of Financial Condition and Results of
Operations should be read in conjunction with the Company’s Consolidated
Financial Statements, Item 16(a) of this Form 10-K.
This
Management’s Discussion and Analysis contains certain forward-looking
statements, as defined by the SEC, such as forecasts and projections of
expected future performance or statements of management’s plans and
objectives. These forward-looking
statements may be contained in filings with the SEC and in press releases and
oral statements. You can identify these
statements by the fact that they do not relate strictly to historical or
current facts. They use words such as
“anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe” and
other words and terms of similar meaning in connection with any discussion of
future operating or financial performance.
These statements are based on the current expectations, estimates or
projections of management and are not guarantees of future performance. Some or all of these forward-looking
statements may not turn out to be what the Company expected. Actual results could potentially differ
materially from these statements.
Therefore, no assurance can be given that the outcomes stated in such
forward-looking statements and estimates will be achieved.
Factors
that could cause actual results to differ materially from our projections
include, among other matters, electric utility restructuring; future economic
and demographic conditions within MPS’s service area and unregulated markets;
changes in tax rates; interest rates or rates of inflation; ability to raise
capital; pace and success of merger and acquisition efforts; terrorism; changes
in the construction industry; changes in Canadian currency rates; length of
sales cycles; developments in state, provincial and national legislative and
regulatory environments in the United States and Canada; ability to recruit
individuals with necessary skill sets; increased competition by existing or new
competitors in the Company’s unregulated markets; changes in technology; new
innovations; changes in NAFTA; increased environmental regulations and other
regulatory or market-based conditions.
Overview
MAM,
a Maine corporation, became a holding company effective June 30, 2003, and owns
all of the common stock of MPS. All of
the shares of MPS common stock were converted on the books into an equal number
of shares of MAM common stock, which are listed on the AMEX under the trading symbol
“MAM.”
Prior
to electric retail deregulation within the state of Maine and its divestiture
of generation, MPS served as a regulated and vertically integrated electric
utility. As a result of deregulation
and generation divestiture, MPS’s revenue model and rate base underwent
significant change. Today, MPS’s returns are based on specifically allowable
rates of return, as permitted by the MPUC and the FERC on various physical and
regulatory assets, referred to as “MPS’s rate base.” While rates of return may remain more stable, should the overall
rate base decline, then earnings will also decline. MPS’s current rate base consists primarily of transmission and
distribution networks (poles, wires, substations buildings and rolling stock),
as well as regulatory assets that include stranded costs associated with the
sale of generation, closure of generation and/or purchase power
agreements. MPS’s primary regulatory
asset or stranded cost is associated with the Wheelabrator-Sherman NUG
Contract, more fully described within this 10-K (see Item 1 above, Business,
“Discussion and Description of the Company’s Growth Strategy;” and “Description
of Maine Public Service Company (“MPS”) and Maine and New Brunswick Electrical
Power Company, Limited (“Me&NB”)”).
In the case of the WS stranded cost, the amount of stranded cost upon
which MPS receives a return is based on the difference between the actual
contract price and the bid price for the facilities output received through a
bid process overseen by the MPUC on a periodic basis.
The
Wheelabrator-Sherman NUG Contract expires in late 2006. However, MPS chose to levelize its stranded
cost payments from consumers, such that the recovery of stranded costs would be
equal over a longer period of time, as opposed to higher consumer costs over a
shorter recovery period, declining on an annualized basis. Consequently, the full recovery of WS
related stranded costs will not occur until 2012, although payments to WS cease
beginning in 2007. As stranded costs
decline, absolute returns will consequently decline as the rate base is
reduced. During the period 2007 through
2012, MPS will experience strong stranded cost freed-up cash flows as a result
of the end of the above-market contract with WS and having levelized its stranded
costs. The deferment of stranded costs
impacts stranded cost freed-up cash flows, but will not impact net income.
Due
to MPS’s declining rate base (as a result of deregulation, generation
divestiture and amortization of stranded costs), combined with current stranded
cost freed-up cash flows forecasts during the period noted, management and
Page 27
of 95
the
board of directors of MPS determined that now is an opportune time to grow and
diversify MPS. As a part of the overall
strategy to grow, as noted, MAM was formed as the holding company for MPS and
other subsidiaries and affiliated companies.
Based on covenants agreed to between MPS and the MPUC in forming the
holding company, restrictions were placed on MAM as it relates to the financial
management of MPS, helping to insulate the regulated utility from possible
detrimental impacts of deregulated companies and diversification. These covenants are described in greater
detail in Item 3, “Legal Proceedings,” Item 3(i)(a) and Item 3(iii)(d).
MAM’s
overall growth strategy consists of the following proposed strategic and
tactical actions:
• Improve the overall operation and economic
viability of MPS:
• Ensure the effective operation of MPS,
ensuring its continued contribution to overall MAM earnings and ensuring
increased effectiveness of capital deployment based on return on capital
employed (“ROCE”) evaluations.
• Improve overall MPS transmission system
security through the development of increased total and available transmission
capacities, deploying capital for new construction based on a FERC allowed rate
of return basis.
• Deploy capital based on the development and
implementation of comprehensive 20-year transmission and distribution system plans
that seek to optimize reliability, while reducing required infrastructure.
• Implement integrated asset management systems
and processes to improve overall reliability and extend assets’ lifecycles.
• Reorganize the utility, creating and
increasing the operational responsibilities of Field Services, migrating
increased decision making to the field.
• Improve overall management of MPS through
improved skill sets, business processes, and systems, including the
installation of a new financial system with utility enterprise management
components.
• Increase the overall integration and
application of technologies to achieve increased productivity, such as
installation of automated meter reading devices.
• Monitor rates to ensure such rates are fully
compensatory and allow for achievement of allowable rates of return on equity,
requesting rate increases as required from regulatory bodies.
• Pursue an acquisition strategy focusing on
the “roll-up” of regional mechanical and electrical engineering firms within
New England and the eastern Canadian provinces to provide a platform for
additional growth and accretive net income to cover organic growth initiatives.
• Identify and pursue acquisitions of smaller
regional mechanical and electrical engineering firms that have the ability to
dominate individual local markets.
• Develop and implement “franchised-type”
systems, processes, products and services to support acquired engineering
firms, limiting required integration issues and improving overall performance.
• Increase product offerings focused on
facility lifecycle management utilizing an information-based technology
platform, providing clients turnkey development of asset assessments and asset
lifecycle plans, including optimization of their capital expenditure programs.
• Increase service offerings in the areas of
energy efficiency and air emissions reductions to complement fee-for-service
engineering services.
• As a part of facility lifecycle management
services, identify and evaluate energy-related assets that can be acquired,
such as central utility plants and central heating and/or cooling districts.
Page 28
of 95
• Identify and evaluate the acquisition or
start-up of an energy supply management services company to complement
engineering and facility lifecycle management services.
• Identify, evaluate and pursue the potential
acquisition of other regulated or unregulated energy companies, such as small
electric utilities or electric utility non-generating assets, small natural gas
local distribution companies, oil distributors and/or propane distributors.
• Implement an aggressive acquisition analysis
team to evaluate utility-type assets and businesses within North America.
• Evaluate opportunities to leverage scale and
synergies with MAM’s ownership of MPS, a regulated transmission and
distribution utility. Potential
synergies include the following:
• Billing, credit collection and remittance
services
• Information technology services
• Engineering services
• Administrative and accounting services
• Call center operations
• SCADA operations
• Human resource related services
• Focus on markets that provide a demographic
and economic hedge to MPS’s service area.
• Focus on related businesses within markets
that have a complimentary cash flow to offset MPS’s inverse bell curve stranded
cost freed-up cash flow.
• Identify, evaluate and pursue the potential
acquisition of regional real estate development and management companies with
an existing and diverse portfolio of real estate assets, focused on secondary
and tertiary growth markets within the eastern Canadian provinces.
• Ensure strong lease coverage of assets with
an asset focus on public sector facilities, such as schools and government
buildings, where leases match the term of financing.
• Focus on a portfolio of commercial and
non-retail properties in both downtown redevelopment districts and business
park settings.
• Focus on the integration of engineering
services in support of facility management.
• Focus on energy supply chain management
optimization.
Beyond
the impacts of electric retail deregulation and generation divestiture,
management closely monitors legislative activities and regulations. Both regulatory and legislative risks are
the major risk concerns impacting MPS.
Management believes that as unregulated energy commodity prices
increase, long-term concerns exist that increased pressures will be placed on
regulated distribution costs.
Management anticipates that scale and technology will be the driving
forces impacting the long-term view of distribution and transmission
assets. Accordingly, management has
concluded that acquiring technology and additional businesses that utilize
common services can create synergies that achieve scale, thus resulting in
better control of increasing operating costs.
In
order to enhance overall financial management capabilities and to ensure
compliance with the Sarbanes-Oxley Act of 2002, MPS is implementing a tier-one
financial system, which includes a utility enterprise management suite. MPS’s need for an improved technology
system, improved management financial reporting and full compliance with
Section 404 of the Sarbanes-Oxley Act has resulted in increased technology and
accounting expenditures. Spreading
these costs over a larger base of businesses is an important part of our
overall strategy.
Although
MPS is prohibited, except under certain, very limited regulatory exceptions,
from owning and operating electric generation, management is closely evaluating
generation resource conditions within northern Maine and the
Page 29
of 95
Canadian
Maritimes control area. Management
believes that peaking capacity is a significant problem within the region and
that this problem is currently exacerbated by uncertainties concerning the
future and cost of Orimulsion® fuel supplies to generation facilities within
New Brunswick, Canada, as well as the future of the Point Lepreau nuclear
generation station also in New Brunswick, Canada. The Company has learned that the New Brunswick Department of
Energy has enlisted a nuclear expert to examine and give advice to the
government on the potential refurbishment of the Point Lepreau nuclear
generation station. Management believes
the estimated anticipated cost of $910 million (CN$) to refurbish Point
Lepreau, is a significant investment in generation that does not provide
additional generation capacity to the region.
Given these and other multi-national issues, policies and decisions that
impact generation supply planning and adequacy, management is concerned about
the uncertainties relative to generation resources availability and the
potential impact such uncertainties may have on MPS’s, and the Company’s future
operations.
To
address these resource availability concerns, MPS is, among other things,
evaluating additional transmission interconnections that could potentially
increase its overall total and available transmission capacities with NB Power. MAM anticipates that the effectiveness of
these lines will in part be dependent upon the future of an additional 345 KV
transmission project currently jointly proposed by NB Power and Bangor Hydro
Electric Company, that would among other things provide an additional
interconnection of NB Power’s system with the New England ISO. This 345 KV transmission project is in the
preliminary permit stages and it is not certain that it will be constructed. Management expects to re-evaluate the MPS
transmission interconnections should this project not proceed.
Due
to the lack of sustainable profitability of EA and its risk profile, MAM also
intends to enhance its unregulated earnings over the next several years to
replace those previously provided by EA.
MAM will retain EA as a subsidiary and maintain its various licenses to
ensure EA’s option of returning to the retail electric sales market should
conditions change and liquidity improve.
Both
the ability to raise the necessary capital and the availability of adequate investment
capital to allow for full implementation of the MAM strategic vision are
critical success factors. MAM is
evaluating a number of financing options, including the possible securitization
of the above-described stranded cost freed-up cash flows (see Item 1 above,
Business, “Discussion and Description of the Company’s Growth Strategy.”)
resulting from deferred stranded cost recovery. Such a technique may require regulatory and/or legislative
approvals. Other options for financing
may include, but are not limited, to the issuance of additional shares of
stock, either common or preferred, and various forms of debt. Debt financing strategies may require that
MAM set a defined dividend policy providing guidance of a target payout range.
Beyond
issues related to capital formation, management anticipates that the
effectiveness of MAM’s strategic vision and acquisition strategy will be
greatly dependent upon the availability and quality of market
opportunities. Management believes that
by evaluating numerous local markets within the New England, U.S. and Atlantic
Canadian provinces, a greater number of small to mid-range acquisition
candidates are possible and is therefore focusing its efforts in these regions.
Existing Operations
The
accompanying consolidated financial statements include the financial results of
the Company and its subsidiaries:
• MPS, its electric transmission and
distribution delivery company, and its wholly-owned, inactive Canadian
subsidiary, Me&NB;
• EA, its CES retail electric marketing
company;
• MAMES, (dba “The Maricor Group”), and its
Canadian subsidiary, Maricor, who provide mechanical and electrical
engineering, energy efficiency, air emissions reduction, and lifecycle asset
management services.
MPS
is an electric transmission and distribution delivery company serving
approximately 35,000 retail electric customers in northern Maine. MPS is subject to the regulatory authority
of the MPUC for its distribution rates and the FERC for its transmission
rates. Current rates are determined
using traditional rate base, and rate of return ratemaking principals,
including a cost-of-service methodology, used by the regulatory agencies. Other investor-owned electric utilities
within the state of Maine are under Alternative Rate Plans (“ARP’s”) and
utilize
Page 30
of 95
Performance
Based Rates (“PBR’s”). MPS continues to
evaluate the merits of an ARP and possible migration to PBR’s. (See Part 1, Item 3, “Legal Proceedings”
Item 3 (ii)(a) above). However,
management believes that implementation of PBR’s under an ARP could result in
detrimental financial impacts due to the lack of growth within MPS’s service
area. Typically, ARP’s with PBR’s
require productivity offsets to achieve allowed rates of return and management
believes such productivity offsets will not be achievable in the absence of
economic growth.
MAMES, and its wholly-owned
Canadian subsidiary, Maricor, offer mechanical and electrical engineering
services, including asset development, energy efficiency services, air
emissions reduction services, and lifecycle asset management services. In addition, MAMES and Maricor offer a range
of solutions to reduce facility lifecycle costs, identify and reduce deferred
maintenance liabilities and improve environmental performance. MAMES’ and Maricor’s value proposition
encompasses the development, management, operation and modernization of
physical assets for environmental and financial sustainability.
Target markets within the
eastern Canadian provinces and Atlantic Canada primarily include, but are not
necessarily limited to, governments, universities and colleges, hospitals and
other health care facilities, schools, commercial retail and office
facilities. While not a target market,
MAMES and Maricor can and do provide engineering-related services to the
industrial sector. MAMES and its
subsidiary, Maricor currently have offices in Presque Isle and Portland, Maine;
Rockland, Massachusetts; and Moncton and Saint John, New Brunswick, Canada.
The Maricor Group’s services
categories generally include:
• Planning & Efficiency Services – facility audit and condition assessments,
asset modernization and development planning, energy and environmental
performance analysis, capital budgeting and planning services and a web
site-based planning advisor;
• Operational Services – asset operations management and asset information management;
• Modernization Services – mechanical and electrical engineering, energy engineering, air
emissions reductions, project management and commissioning services; and
• Development Services – energy asset ownership, design and build services, project
management and commissioning services, such as central utility or district
energy projects.
This
section and the accompanying text explain the general financial condition of
the Company and its subsidiaries and their results of operations. This explanation includes:
• factors that affect our business;
• the sources of our revenues and changes
between years;
• our operating expenses and changes between
years;
• the sources of our operating capital; and
• the impact of the above on our financial
condition.
Critical Accounting Policies
In
preparing the financial statements in accordance with generally accepted
accounting principles, management must often make estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues, expenses and
related disclosures at the date
of the financial statements and during the reporting period. Some of those judgments can be subjective
and complex, and actual results could differ from those estimates. The Company’s most critical accounting
policies include the determination of the appropriate accounting for its
pensions and other post-retirement benefits, the recognition of its revenues,
the effects of utility regulation on its financial statements and its risk
management activities.
Revenue Recognition
MPS
records an estimate for revenue for electricity delivered, but not yet billed
to customers. This estimate requires
MPS to make certain assumptions. A
change in those assumptions could cause the amounts reported as revenues to
change. EA’s previous sales can be
classified into two general categories:
SOS in CMP’s service territory which
Page 31
of 95
expired
February 28, 2002, and CES sales to individual retail customers within the
state of Maine, all of which expired by February 27, 2004.
For SOS, revenues were received and expenses were paid directly by an
escrow agent which was controlled by Engage Energy America, LLC (“Engage”). EA received a percentage of the net profit
from the sale of energy. CMP bore SOS
account collection risks, as they were required to remit the amounts billed 26
days after the billing date to the escrow account mentioned above and maintain
the billing and customer service relationship.
EA recorded the accrued net margin of the SOS activity as revenue in the
financial statements. For CES sales, EA
negotiated the price directly with the customer, maintained customer service
responsibility and had collection risk.
EA has withdrawn from the market until market conditions improve and no
longer serves CES or SOS customers. CES activity is recorded on a gross basis
to include the related revenues and purchased power expenses. Additionally, EA’s activity has been
accounted for as non-trading since management has determined it does not meet
the definition of a trader as defined in EITF 98-10 which was amended by EITF
02-03. Refer to Item 16(a) of this Form
10-K, Note 3 to the Consolidated Financial Statements, “Energy Atlantic” for
further discussion.
Pension and Other
Post-retirement Benefit Plans
The
Company has pension and other post-retirement benefit plans, principally
healthcare benefits, covering substantially all of its employees and
retirees. In accordance with Statement
of Financial Accounting Standards No. 87, “Employer’s Accounting for Pensions,”
and Statement of Financial Accounting Standards No. 106, “Employer’s Accounting
for Post-retirement Benefits Other Than Pensions,” the valuation of benefit
obligations and the performance of plan assets are subject to various
assumptions. The primary assumptions
include the discount rate, expected return on plan assets, rate of compensation
increase, health care cost inflation rates, expected years of future service
under the pension benefit plans and the methodology used to amortize gains or
losses. Changes in those assumptions
could also have a significant effect on the Company’s non-cash pension income
or expense or the Company’s post-retirement benefit costs. For additional information on the Company’s
benefit plans, see Item 16(a) of this Form 10-K, Note 10 to the Consolidated
Financial Statements, “Benefit Plans,” which is incorporated in this section by
this reference.
Utility Regulation
MPS
is subject to the regulatory authority of the MPUC and the FERC. As a result of the ratemaking process, the
applications of accounting principles by MPS differ in certain respects from
applications by non-regulated businesses.
Approximately 84% of the Company’s 2003 revenues, as depicted in the
“Operating Revenues and Energy Deliveries” section below, derived from MPS’s
regulated operations are accounted for pursuant to Statement of Financial
Accounting Standards No. 71, “Accounting for the Effects of Certain Types of
Regulations.”
Prior
to the start of deregulation in Maine on March 1, 2000, the MPUC determined the
amount of stranded costs to be recovered via rates. MPS’s annual amortization of its stranded costs represents the
amounts allowed by the MPUC in the determination of revenue requirements.
Results of Operations
Earnings and Dividends
Earnings
per share and net income for 2003, along with the corresponding information for
2002 and 2001 are as follows:
|
|
|
(Dollars
in Thousands)
|
|
|
Net Income *
|
|
2003
|
|
2002
|
|
2001
|
|
|
MAM/MAMES
|
|
$
|
(416
|
)
|
$
|
—
|
|
$
|
—
|
|
|
MPS-Core T&D
|
|
3,338
|
|
3,099
|
|
4,340
|
|
|
EA
|
|
(116
|
)
|
3,444
|
|
897
|
|
|
Total Company
|
|
$
|
2,806
|
|
$
|
6,543
|
|
$
|
5,237
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per Share
|
|
$
|
1.78
|
|
$
|
4.16
|
|
$
|
3.33
|
|
*
Due to the immateriality of elimination
amounts, they have been grouped with appropriate line items
Page 32
of 95
Net
income above is allocated based upon the segment allocation as presented in
Item 16(a) of this Form 10-K, Note 4 of the Notes to Consolidated Financial
Statements, “Segment Information.”
As
a part of the formation of the holding company, certain MPS staff were
transferred to MAM. Also, certain administrative, legal, professional,
governance, and professional costs were assigned to MAM, following MPUC
approved cost allocation process. In
addition, certain costs associated with merger and acquisition due diligence
activities were included in MAM costs.
In December, 2003, MAM formed MAMES and MAMES’ Canadian subsidiary, Maricor. In addition, during the same time frame
Maricor purchased Eastcan Consultants, a mechanical and electrical engineering
firm headquartered in Moncton, New Brunswick, Canada, with an office in Saint
John, New Brunswick.
MPS
core T & D earnings were $3,378,000 for 2003, compared to $3,099,000 and
$4,340,000 in 2002 and 2001, respectively.
Earnings for 2003 increased by $239,000 over earnings in 2002. Sales in 2003 increased by 1.9% over 2002,
contributing an additional $203,000, net of income taxes. As more fully explained in the “Legal
Proceedings” section of this Form 10-K, the MPUC allowed recovery, over seven
years, of the VERP expenses charged to 2002 earnings, resulting in an increase
in 2003 net income of $236,000, net of income taxes, after considering two
months of amortization. In addition,
reductions in transmission and distribution expenses of $131,000, net of income
taxes, and in interest costs of $192,000, net of income taxes, also contributed
to the increase in earnings. Offsetting
these increases in earnings were additional expenses of $245,000, net of income
taxes, associated with the approval of the holding company and increases in
depreciation and amortization of $122,000, net of income taxes. Earnings for 2002 compared to 2001 were
impacted by incremental charges for MPS’s Voluntary Early Retirement Program
(“VERP”) of $242,000, net of income taxes, and expenses associated with seeking
approval for the formation of the holding company of $105,000, net of income
taxes. MPS incurred additional expenses
for employee benefits, principally pension and medical costs, and insurance
costs, resulting in a reduction in earnings of $723,000, net of income
taxes. In addition, consulting fees for
evaluating business processes at MPS and legal expenses for regulatory affairs
and compliance with provisions of the Sarbanes-Oxley Act of 2002, further
reduced net income by $575,000, net of income taxes. Offsetting these additional expenses was a reduction of MPS’s
borrowing costs of $361,000, net of income taxes, and increased operating
revenues for MPS of $235,000, net of income taxes, as 2002 sales were 1.4% more
than 2001 sales.
In
2003, EA incurred a loss of $116,000 with the reduction in 2003 CES sales,
compared to the two previous years, and with the termination of SOS service in
CMP’s territory after February 28, 2002.
EA earnings for 2002 were $3,444,000, or $2.19 per share. As more fully explained in the “Energy
Atlantic Activities” section below, EA’s earnings include $1.89 per share representing
the recognition in September 2002, of the final settlement between EA and
Engage Energy America, LLC (“Engage”) and the reversal of regulatory
assessments associated with power arrangements. EA earnings in 2001 reflect a $1.08 million charge in accordance
with a settlement agreement with EA’s supplier for Standard Offer Service in
Central Maine Power Company’s service territory, Engage Energy America,
LLC. This charge reduced earnings per
share by $.69.
Return
on equity (net income divided by average shareholders’ equity) for 2003 was
6.0% compared to 14.6% for 2002 and 12.7% for 2001. The core T&D business earned a return on equity of 8% in 2003
compared to 7.6% and 10.5% for 2002 and 2001, respectively. As explained in the “Legal Proceedings”
section of this Form 10-K, the MPUC authorized a return on equity of 10.25%
starting November 1, 2003, compared to 10.7% prior to that date.
Effective
October 1, 2001, the Board of Directors increased the quarterly dividend by
$.03 per share from $0.32 per share to $0.35 per share, or $1.40 per share per
year. The quarterly dividend was
increased by $0.02 per share to $0.37 per share effective October 1, 2002, for
an annual dividend payment of $1.48 per share.
Effective January 1, 2004, the Board of Directors increased the
quarterly dividend by $0.01 per share to $0.38 per share, for an annual
dividend of $1.52 per share.
Off-Balance Sheet Arrangements
Except for operating leases used for office and
field equipment, vehicles and computer hardware and software, accounted for in
accordance with Financial Accounting Standards No. 13 (“FAS 13”), “Accounting
for Leases” and
Page 33
of 95
noted in Footnote 12 to these financial statements,
the Company has no other off-balance sheet arrangements. See Item 16(a) of this Form 10-K, Note 12 to
Consolidated Financial Statements, “Commitments, Contingencies and Regulatory
Matters,” under “Off-Balance
Sheet Arrangements” for a summarization
of payments for leases for a period in excess of one year for the years ended
December 31, 2003 and 2002.
Operating Revenues and Energy
Deliveries
Consolidated
revenues and Megawatt Hours (“MWH”) delivered for the years 2003, 2002 and 2001
are as follows:
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
(Dollars in Thousands)
|
|
Dollars
|
|
MWH
|
|
Dollars
|
|
MWH
|
|
Dollars
|
|
MWH
|
|
|
Residential
|
|
$
|
13,264
|
|
175,435
|
|
$
|
12,672
|
|
169,489
|
|
$
|
12,382
|
|
166,012
|
|
|
Large Commercial
|
|
4,791
|
|
165,467
|
|
4,799
|
|
166,954
|
|
4,684
|
|
160,575
|
|
|
Medium Commercial
|
|
5,292
|
|
106,073
|
|
5,166
|
|
103,840
|
|
5,242
|
|
107,207
|
|
|
Small Commercial
|
|
6,400
|
|
89,882
|
|
6,091
|
|
86,639
|
|
5,994
|
|
85,605
|
|
|
Other Retail
|
|
788
|
|
3,357
|
|
774
|
|
3,345
|
|
767
|
|
3,309
|
|
|
Total Regulated Retail
|
|
30,535
|
|
540,214
|
|
29,502
|
|
530,267
|
|
29,069
|
|
522,708
|
|
|
Energy Atlantic Competitive Energy Supply
|
|
6,064
|
|
114,405
|
|
6,899
|
|
148,072
|
|
15,771
|
|
375,768
|
|
|
Total Retail
|
|
36,599
|
|
654,619
|
|
36,401
|
|
678,339
|
|
44,840
|
|
898,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Operating Revenues
|
|
1,262
|
|
|
|
1,901
|
|
|
|
2,711
|
|
|
|
|
Total Operating Revenues
|
|
37,861
|
|
|
|
38,302
|
|
|
|
47,551
|
|
|
|
|
Energy Atlantic Standard Offer Service
Margin
|
|
—
|
|
|
|
5,802
|
|
|
|
2,147
|
|
|
|
|
Total Revenues
|
|
$
|
37,861
|
|
|
|
$
|
44,104
|
|
|
|
$
|
49,698
|
|
|
|
* Due to
the immateriality of elimination amounts, they have been grouped with
appropriate line items.
For
2003, regulated retail sales for MPS were 540,214 MWH compared to 530,267 MWH
and 522,708 MWH in 2002 and 2001, respectively. 2003 retail sales were 1.9% higher than sales in 2002 and 3.3%
higher than sales in 2001. Residential
sales in 2003 were 3.5% higher than 2002 sales and 5.7% higher than 2001. This increase is believed to be attributable
to a colder than normal winter in 2003, as compared to 2002.
Sales
to MPS’s large commercial customers in 2003 were 0.9% less than 2002, but 3.0%
higher than 2001 sales. Sales to MPS’s
largest customer, McCain Foods, were 65,814 MWH, 0.7% less than 2002 sales of
66,301 MWH, but 12.3% higher than 2001 sales of 58,629 MWH. Sales to food processing customers, other
than McCain Foods, in 2003 were 15,858 MWH compared to 15,831 MWH in 2002 and
23,225 MWH in 2001. The closing of
Maine Frozen Foods in 2002 was the principal reason for the reduction in
sales. Sales to wood product customers
in 2003 were 76,248 MWH, 1.6% less than 2002 sales of 77,495 MWH, but 4.6% more
than 2001 sales of 72,922 MWH. These
customers have benefited from the historically low interest rates and the
increased demand for new homes and home remodeling projects.
Sales
to MPS’s medium commercial customers increased by 2,233 MWH to 106,073 MWH in
2003, as compared to 103,840 MWH in 2002, but were 1,134 MWH less than 2001
sales of 107,207 MWH. Small commercial
customer sales were 89,882 MWH, compared to sales in 2002 and 2001 of 86,639
MWH and 85,605 MWH, respectively. The
increase in sales to these two classes of customers reflects the colder than
normal weather in 2003, as well as the general improvement of overall regional
economic conditions, including the retail sector.
The
MPUC has jurisdiction over MPS’s retail rates.
On November 1, 2003, and on October 1, 2002, MPS’s rates were increased
by approximately 3% and 2% respectively.
These retail rate increases included the retail portion of previously
FERC approved transmission increases.
The FERC has jurisdiction over MPS’s transmission rates,
Page 34
of 95
including
the rates charged for wheeling revenues, as discussed below. For more information on the regulatory
orders approving the recent rate increases, see Item 3, “Legal Proceedings,”
Item 3 (ii) (c) and (d) of this Form 10-K.
As
more fully explained in the “Energy Atlantic Activities” section below, EA
provided CES and SOS during the three-year period. In 2001, CES sales of 375,768 MWH produced $15.8 million of
revenues. In 2000, with its arrangement
with Engage Energy America, LLC (“Engage”), EA provided CES service to several
large customers, principally in southern Maine. However, these contracts expired in 2001, resulting in reduced
sales and revenues for 2002 and 2003.
In addition, EA had difficulties procuring competitive energy supplies,
given MPS’s conservative fiscal policies regarding risk tolerance and credit
coverage. As a result, sales in 2002
were 148,072 MWH and $6.9 million, further dropping to 2003 sales of 114,405
MWH and $6.1 million in revenues. The
SOS margin represents the net margin sales of SOS to approximately 525,000
residential and small commercial customers in Central Maine Power Company’s
service territory from March 1, 2000 through February 28, 2002. As more fully
explained in the “Energy Atlantic Activities” section below, EA was not the
successful bidder for providing SOS after March 1, 2002, and received a final
account settlement with Engage in 2002.
This final account settlement with Engage, of approximately $4.6
million, before income taxes, is reflected in the 2002 SOS margin of $5.8
million. In 2001, the SOS margin of
$2.15 million reflects a $1.8 million before-tax charge for a contract
settlement with Engage. As noted
herein, EA has now ceased operations and no longer serves customers in
Maine. Its inactive status will remain
under review by management, and the Company intends to maintain certain
licenses in order to preserve the option of returning to the market should
market conditions and other risk factors improve.
Other
operating revenues in 2003 were $1,262,000 compared to $1,901,000 in 2002 and
$2,711,000 in 2001. Wheeling revenues
in 2003 were $318,000 less than 2002 and $448,000 less than 2001, reflecting
the reduction in use of MPS’s transmission system by on-system generators. As more fully explained in Item 3 “Legal
Proceedings,” Item 3(ii) (b) of this Form 10-K, the MPUC, in its stranded cost
review, adjusted the treatment of certain customer discounts through flexible
pricing adjustments, effective March 1, 2002.
As a result, the revenues recognized from flexible pricing adjustments
in 2003 were $335,000 less than 2002 and $1,096,000 less than 2001.
Operating Expenses
For
the three-year period 2001 to 2003, unregulated energy supply, regulated
operation and maintenance expenses and unregulated operation and maintenance
expenses and stranded costs are as follows:
|
(Dollars in Thousands)
|
|
2003
|
|
2002
|
|
2001
|
|
|
Unregulated Energy Supply – EA
|
|
$
|
5,220
|
|
$
|
5,533
|
|
$
|
14,984
|
|
|
Regulated Operation and Maintenance
|
|
|
|
|
|
|
|
|
Transmission and Distribution
|
|
$
|
3,114
|
|
$
|
3,334
|
|
$
|
3,343
|
|
|
Customer Service
|
|
1,452
|
|
1,635
|
|
1,452
|
|
|
Administrative and General
|
|
7,857
|
|
8,076
|
|
5,616
|
|
|
Total Regulated Operation and Maintenance
|
|
$
|
12,423
|
|
$
|
13,045
|
|
$
|
10,411
|
|
|
Unregulated Operation and Maintenance
|
|
|
|
|
|
|
|
|
Holding Company Formation (MPS)
|
|
$
|
639
|
|
$
|
209
|
|
$
|
—
|
|
|
Energy Atlantic
|
|
1,018
|
|
1,445
|
|
1,226
|
|
|
MAM/MAMES
|
|
696
|
|
—
|
|
—
|
|
|
Total Unregulated Operation &
Maintenance
|
|
$
|
2,353
|
|
$
|
1,654
|
|
$
|
1,226
|
|
|
Stranded Costs
|
|
|
|
|
|
|
|
|
Wheelabrator-Sherman
|
|
$
|
8,711
|
|
$
|
8,308
|
|
$
|
9,003
|
|
|
Maine Yankee
|
|
2,661
|
|
3,008
|
|
3,170
|
|
|
Seabrook
|
|
1,110
|
|
1,110
|
|
1,110
|
|
|
Amortization of Gain from Asset Sale
|
|
(443
|
)
|
(2,988
|
)
|
(4,863
|
)
|
|
Deferred Fuel and Special Discounts
|
|
(3,278
|
)
|
(677
|
)
|
840
|
|
|
Total Stranded Costs
|
|
$
|
8,761
|
|
$
|
8,761
|
|
$
|
9,260
|
|
*Due to the
immateriality of elimination amounts, they have been grouped with appropriate
line items.
Page 35
of 95
The
unregulated energy supply expenses represent EA’s purchases of energy to supply
their CES customers. As more fully
explained in the “Energy Atlantic Activities” section below, EA was purchasing
power from Engage Energy America, LLC (“Engage”) for a two-year period that
ended on February 28, 2002. Beginning
March 1, 2002, for a two-year period, EA was awarded a contract by the MPUC for
40% of the output (55,000 MWH) from the Wheelabrator-Sherman facility to be used
for CES sales in northern Maine. In
addition, EA has a power supply arrangement with Duke Energy Trading &
Marketing (“DETM”) to provide power to CES customers in southern and central
Maine. The reduction in purchases of
energy supply from $14,984,000 in 2001 and $5,533,000 in 2002 to $5,220,000 in
2003 reflects the reduction in sales achieved by EA, as presented in the
“Operating Revenues and Energy Deliveries” section above. During 2000, the first year of deregulation
in Maine, several large industrial customers purchased power from EA under
one-year agreements, which expired at various times during 2001.
Transmission
and distribution expenses in 2003 were $3,114,000, a reduction of $220,000 from
expenses in 2002 and $229,000 from expenses in 2001. The reduction in tree-trimming expenses due to the “in-sourcing”
of vegetation management, was the primary reason for the decrease in expenses
in 2003 compared to 2002 and 2001.
In
2003, customer service expense was $1,452,000 compared to $1,635,000 and $1,452,000
for 2002 and 2001, respectively. In
2002, MPS’s charge-offs for bad debts increased by $191,000 over 2001,
reflecting the bankruptcies and plant closings of several customers during
2002, while 2003 approximated 2001. The
implementation of automatic meter reading in 2003, for approximately one third
of our customers, helped to further reduce customer service costs compared to
expenses in 2002.
Administrative
and general expenses in 2001 were $5,616,000 increasing to $8,076,000 in 2002
and $7,857,000 in 2003. As more fully
explained in the “Employee” section below, employees representing approximately
7% of the workforce participated in a voluntary early retirement program
(“VERP”) in 2002. The cost of the
program was $402,000 which was charged to fourth quarter 2002 earnings. As more fully explained in the “Legal
Proceedings” section above, in early 2003 MPS filed for a rate increase. One of the elements in the rate request was
recovery of these VERP costs. However,
recovery of these costs was not approved by the MPUC when the program was
instituted in 2002. When the MPUC
issued its rate orders in the fall of 2003, thereby assuring MPS of the
recovery of the $402,000 in VERP costs, MPS reduced 2003 administrative and
general expenses. After adjusting for
the impact of the VERP discussed above, employee benefits, principally employee
and retiree medical expenses and pension expenses were $2.1 million in 2003
compared to $2.3 million in 2002 and $1.5 million in 2001. The increases in pension expenses in 2002
and 2003 reflect the lower discount rates used to determine pension liabilities
and lower returns realized in pension investments with the sluggish investment
markets in 2002 and 2001. Medical costs
continue to escalate comparable to national trends. As mentioned in the “Employee” section below, employee
contributions have increased and retirees began contributing to help offset
escalating costs. In 2003, regulatory,
consulting and legal expenses totaled $2.1 million compared to $1,598,000 in
2002 and $824,000 in 2001. The dramatic
increase in these expenses in 2003, and 2002 over 2001, reflect costs
associated with compliance with the Sarbanes-Oxley Act of 2002; legal and rate
consulting assistance in the preparation, filing and advocacy of MPS’s rate
plan filed with the MPUC during the first quarter of 2003 and approved by the
MPUC in the fourth quarter of 2003; legal services associated with the
preparation, filing and advocacy concerning MPS’s federal Open Access
Transmission Tariff (“OATT”) filed in the second quarter of 2003 with a final
FERC rate order in the first quarter of 2004; the completion of transmission
and distribution, as well as information systems benchmarking audits, enabling
increased asset management, increased prioritization of capital expenditures,
increased productivity and improved reliability; and finally, review of
financial strategies and financing options.
MPS’s insurance expenses in 2003 increased by $168,000 over 2002 and
were $289,000 more than 2001. These
increases have followed the national trends of increased premiums for property
and casualty insurance after the terrorist attacks on September 11, 2001, and
increased Directors’ and Officers’ liability insurance costs following
corporate scandals at several major corporations.
Unregulated
operation and maintenance expenses were $2,353,000 in 2003 compared to
$1,654,000 in 2002 and $1,226,000 in 2001.
In late 2002, and for the first six months of 2003, MPS incurred
expenses associated with the formation of the new holding company, MAM, of
$209,000 and $639,000, respectively.
During 2003, EA’s
Page 36
of 95
operating
expenses were $1,018,000 compared to $1,445,000 in 2002 and $1,226,000 in
2001. Expenses in 2002 were higher due
to an increase in bad debt expense, legal expenses associated with the Engage
settlement and consulting fees. During
2003, EA reduced costs with the reduction in business activity. In July 2003, MAM began formally assessing
business opportunities and potential acquisition targets. During the last six months of 2003, MAM and
MAMES collectively spent $696,000 on these activities.
Beginning
on March 1, 2000, MPS began recovering stranded costs from its retail
customers. As discussed in Item 3
“Legal Proceedings” section, the MPUC reviewed MPS’s stranded costs and
adjusted MPS’s recovery effective March 1, 2002. MPS recognized stranded costs of $8,761,000 for 2003 and 2002 and
$9,260,000 for 2001.
The
reduction of stranded costs in 2003 and 2002 reflects the reduction in revenue
requirements as discussed in Item 3 of the “Legal Proceedings” section. The stranded costs for WS and Maine Yankee
represent actual cash expenses during the year, while other costs reflect the
amortization or recognition of regulatory assets and regulatory liabilities.
Operating Capital and Liquidity
The
Company’s “Statements of Consolidated Cash Flows,” of the Company’s
Consolidated Financial Statements as presented in Item 16(a) of this Form 10-K,
reflects the Company’s liquidity and sources of operating capital. Net income of $2.8 million for 2003
generated $3.9 million in cash flow provided by operating activities. The change in deferred regulatory and debt
issuance costs of $6.8 million, principally the deferral of additional WS
stranded cost, which was partially offset by an increase in deferred income
taxes of $3.6 million, and accounted for the biggest charge on cash flow
compared to prior years. Net cash flow
used for financing activities totaled $2.7 million. During 2003, $2.9 million was paid in dividends and $3.1 million
was used for sinking fund payments to retire long-term debt. The dividend payment amount reflects five
quarters of dividends paid during 2003 due to timing of funding requirements. These payments were offset by short-term
borrowings of $3.35 million. In 2003,
$2.8 million of net cash flow was used for investing activities. The Company invested $4.9 million in
electric plant and an additional $527,000 in MAMES, principally its purchase of
Eastcan Consultants, Inc. During 2003,
the final $2.1 million was withdrawn from the trust account for the 2000 series
of tax-exempt bonds for the construction of qualifying distribution property, and
$525,000 was received for the partial redemption of Maine Yankee common stock.
In
2002, net cash flows of MPS provided by operating activities were $6.9 million,
while net income for the year was $6.54 million. In 2002, $3 million of
the gain from the 1999 sale of the generating assets was amortized, while
regulatory assets increased by $1.9 million to reflect the rate treatment of
stranded costs, which both reduced cash flows.
During 2002, MPS paid $2.2 million in dividends, retired $1.2 million of
long-term debt and reduced short-term borrowings by $1.2 million, for a total
of $4.6 million used for financing activities. In 2002, $5.9 million was
invested in electric plant with $3.7 million withdrawn from the trust account
for the tax-exempt bonds. In addition, MPS received approximately $375,000
for the partial redemption of its Maine Yankee common stock. As of
December 31, 2002, approximately $2.1 million remained in the tax-exempt trust
fund to be used for the construction of qualifying property through October
2003.
Net
cash flows provided by operating activities were $10.1 million in 2001.
Net income for the year was $5.24 million. The collection of
accounts receivable, principally the collection by EA of the SOS service
receivable from the escrow agent, accounted for most of the increase in cash
flows from operating activities. In
2001, MPS paid $2.1 million in dividends while reducing short-term borrowings
and long-term debt by $2 million. During 2001, MPS received $1.05 million
from a settlement with CMP concerning the 1999 sale of Wyman Unit No. 4, as
well as $0.5 million for a partial stock redemption from Maine Yankee. As
mentioned above, MPS has available proceeds from the issuance of tax-exempt
bonds in 2000. During 2001, $2.0 million was withdrawn from the trust
account for the construction of qualifying distribution property. As of
December 31, 2001, approximately $5.7 million remained in the tax-exempt bond
trust fund to be used for the construction of qualifying property. In
2001, $4.7 million was spent for electric plant.
For
additional information regarding construction expenditures for 2001 to 2003 and
anticipated construction expenditures for 2004, see Items 16(a) of this Form
10-K, Note 12 of Notes to Consolidated Financial Statements, “Commitments,
Contingencies and Regulatory Matters — Construction Program.”
Page 37
of 95
To
satisfy working capital requirements, MPS uses short-term borrowings from its
revolving credit agreement of $6 million. The agreement is secured by $6
million of first mortgage bonds and its due date has been extended to June 6,
2004. In addition, on October 1, 2003, MPS executed an additional $3
million line of credit with the Bank of New York. This new facility is unsecured and will expire on March 29,
2004. MPS is currently seeking
extensions of these facilities and management believes this effort will be
successful. Interest rates on this new
facility are comparable to the rates on the existing revolving credit
agreement. The additional facility
provides an additional source of short-term borrowings in the event required
borrowings exceed the existing revolving credit agreement. At the end of 2003, MPS had $6.2 million of
short-term debt compared to $2.8 million and $3.95 million at the end of 2002
and 2001, respectively. This short-term debt increase is a result of the
long-term repayments described above.
During 2001 to 2003, the interest rates on these short-term borrowings
were below the existing prime rate. For additional information on the
short-term credit facility, see Item 16(a) of this Form 10-K, Note 6 of the
Notes to Consolidated Financial Statements, “Short-Term Credit
Arrangements.” Based on current projections for 2004, the Company
estimates that operating cash flows and short-term borrowings via available
credit facilities will be sufficient to cover MPS’s other sinking fund
payments, construction activities, and other financial obligations.
Capital Resources
The
Company has the ability to raise capital through the issuance of common and
preferred stock, as approved by the stockholders at the May 30, 2003, Annual
Meeting. The Company is authorized to issue up to 5,000,000 shares of
common stock. In addition, the Company’s
Articles of Incorporation authorize the issuance of 500,000 shares of preferred
stock with the par value of $0.01 per share.
MPS can also issue $2.5 million of first mortgage bonds and $14.3
million of second mortgage bonds without bondable property additions.
With
the sale of the generating assets and the use of sale proceeds to redeem debt,
MPS’s long-term debt has decreased. On January 1, 1999, MPS had $47.2
million of long-term debt compared to $30.68 million at the end of 2003.
MPS’s long-term debt currently consists of two series of tax-exempt bonds
issued on behalf of MPS by the Maine Public Utility Financing Bank (“MPUFB”)
totaling $22.6 million, and a series of bonds issued by FAME of $8.08 million,
which provided MPS with the funds necessary for the up-front payment to
restructure the WS PPA, as mentioned above.
The
MPUFB has issued its tax-exempt bonds on behalf of MPS for the construction of
qualifying distribution property. Originally issued for $15 million and
reduced with generating asset sale proceeds, the 1996 Refunding Series had
$13.6 million outstanding at December 31, 2003 and is due in 2021. On
October 19, 2000, the 2000 Series of bonds was issued in the amount of $9
million, with these bonds due in 2025. The proceeds of the 2000 Series
were placed in trust to be drawn down for the reimbursement of issuance costs
and for the construction of qualifying distribution property. For both
tax-exempt bond series, a long-term note was issued under a loan agreement
between MPS and the MPUFB, with MPS agreeing to make payments to the MPUFB for
the principal and interest on the bonds. Concurrently, pursuant to a
letter of credit and reimbursement agreement, the Bank of New York has
separately issued its direct pay letter of credit (“LOC”) for the benefit of
the holders of each series of bonds. Both LOC’s are due to expire in June
2004. Management is currently seeking an extension of this facility and
believes the effort will be successful.
To secure MPS’s obligations under the letter of credit and reimbursement
agreement for the 1996 Refunding Series, MPS issued second mortgage bonds in
the amount of $14.4 million in June 2002. For the 2000 series, MPS issued
first and second mortgage bonds, in the amounts of $5 million and $4.525
million, respectively, to secure MPS’s obligation under the letter of credit
and reimbursement agreement for this series. For both series, MPS has the
option of selecting weekly, monthly, annual or term interest rate
periods. For both series, MPS has continued to use the weekly interest
rate period. Since issuance, the average of these weekly rates was 2.99%
and 1.97% for the 1996 Refunding Series and the 2000 Series,
respectively. As more fully explained in the “Legal Proceedings” section
of this Form 10-K, in September 2003, MPS executed an interest rate swap
agreement with Fleet National Bank for the remaining terms of the issues with
an effective fixed rate of 4.57% for the 1996 series and 4.68% for the 2000
series. By its rate order in Docket No.
2003-85, the MPUC approved the execution of the agreements and allowed recovery
of the additional interest costs.
On
May 29, 1998, FAME issued $11,540,000 of its Taxable Electric Rate
Stabilization Revenue Notes, Series 1998A (MPS) (the “Notes”) on behalf of
MPS. 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
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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 MPS and the Capital Reserve Fund held by the Trustee.
MPS issued $4 million of its first mortgage bonds and the MPUC also
approved the execution of an interest rate swap agreement with Fleet National
Bank for the remaining term of the issue with an effective fixed rate of 2.79%.
In accordance with rate stipulations approved by the
MPUC, for ratemaking purposes, MPS is required to maintain a capital structure
not to include more than 51% common equity for the determination of delivery
rates.
In the order approving the reorganization of MPS and
the formation of the new holding company, Maine & Maritimes Corporation,
parties stipulated to several conditions.
The following relate to the availability of capital resources for MAM
via its relationship with MPS:
• MPS will not make
any loan to, or guarantee or assume any obligation of, MAM or any of its
affiliates without prior MPUC approval.
• The MPUC will not
place additional restrictions, in advance, on the dividend policy of MPS. The Board of Directors of MPS will continue
to set dividend policy for MPS with due regard for the financial performance, needs
and health of MPS and the maintenance of a safe, efficient and reasonable
capital structure. Commencing on July
1, 2003, if at any time MPS’s common dividend payout ratio (dividends per share
divided by earnings per share) exceeds 1.0 (i.e. 100%) on a two-year rolling
average basis, MPS will notify the MPUC in writing within thirty (30) days of
the end of the calendar quarter (assuming a dividend is paid July 1, 2003, the
initial two year period shall be April 1, 2001 through March 31, 2003.) The required notification should explain the
circumstances (extraordinary or not) of this event and the financial condition
of MPS. Moreover, the MPUC reserved the
right in the future, should financial circumstances warrant, to impose limitations
on the dividend policy of MPS.
• Securities
issuances by MPS will be done independently of MAM and subject to such MPUC
approvals as required. The proceeds of
any securities issued by MPS will be used exclusively by MPS for its business.
• MAM’s total
non-utility investment, excluding accumulated unregulated retained earnings,
will not exceed fifty million dollars (US$50,000,000) and such amount will
exclude retained earnings from EA, provided that MPS may at any time seek an
enlargement of this limitation for good cause shown.
• Without prior MPUC
approval, MAM will not sell, pledge or otherwise transfer any common stock of
MPS.
• To protect and
maintain the financial integrity of the regulated utility, MPS and MAM agreed
to maintain the common equity ratio of MPS at a level of not less than forty
eight percent (48%) of the total capital at all times, provided that the MPUC
may establish, for good cause shown, a lower ratio in connection with its
authorization of a future debt issuance proposed by MPS. Total capital is defined as the sum of the
following components: common equity,
preferred equity, long-term debt, current maturities long-term debt (“CMLTD”),
long-term capital leases, current maturities long-term capital leases, and
short-term debt.
Energy
Atlantic Activities
EA’s net loss for 2003 was $116,000 compared to net
income of $3,444,000 and $897,000 for 2002 and 2001, respectively. EA’s loss in 2003 reflects the gradual
termination of service as contracts expire in northern Maine. The current standard offer pricing in Maine,
the lack of wholesale choices and liquidity within northern Maine, and the
increased credit requirements associated with acquiring wholesale electricity
supply have hampered EA in competing for sales. The Company maintains a conservative risk management philosophy
and has limited the transactions that EA can undertake as a buyer or seller in
order to limit and mitigate potential transaction risk exposures. EA earnings for 2002 and 2001 were impacted
by settlements with its energy provider.
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Energy
Atlantic’s historical energy sales can be classified into two general
categories: Standard Offer Service (“SOS”) in CMP’s service territory
which expired February 28, 2002, and Competitive Energy Supply (“CES”) sales to
individual retail customers within the state of Maine. Effective February 27, 2004, EA no longer
serves CES or SOS retail customers and has discontinued service. Originally, EA obtained power for the sales
in CMP’s territory under an exclusive wholesale power sales agreement with
Engage Energy America, LLC.
During
the third quarter 2002, EA and Engage concluded their business relationship
pursuant to the terms of their agreement.
Following completion of the final scheduled audit, the final escrow
disbursements were made to EA and Engage on September 30, 2002. As a result of the final account settlement,
EA recognized the $4.8 million of additional standard offer service SOS revenue
during the third quarter of 2002 with an after-tax impact of $2.9 million, or
$1.84 per share.
EA
previously entered into a contract for 40% of the output of the WS energy
facility for the two years beginning March 1, 2002 and expiring on February 29,
2004. The output from this take-or-pay contract amounted to approximately
55,000 MWH annually and was being used to provide electricity for additional
CES sales within MPS’s service territory. This contract was a take-or-pay
contract, which carried more counterparty risk than others entered into by
EA. To mitigate this risk, EA entered into a contract with NB Power,
whereby NB Power committed to buy WS output in excess of load requirements in
the MPS service territory at a rate indexed to the price of 3% Sulphur Max No.
6 residential oil into New York Harbor, which was intended to reflect NB
Power’s avoided cost, subject to a floor and ceiling. All output was sold
to CES customers, therefore limiting the risk that energy would be sold to NB
Power. In addition, NB Power committed to sell electricity to EA when
load exceeded WS output at a fixed on and off-peak rate.
In
addition, EA had a power supply relationship with Duke Energy Trading and
Marketing (“DETM”) for electricity in CMP’s service area. In connection
with this relationship, and certain transactions between EA and DETM, MPS
provided a contractual guarantee on behalf of EA in an aggregate amount of one
million dollars ($1,000,000). This guarantee was related specifically to
the delivery and/or receipt of electric power between EA and DETM. This
guarantee was renewed in September of 2002 for an additional year. Effective March 21, 2003, DETM agreed to
waive this credit requirement in lieu of EA’s commitment to maintain a $1
million ($1,000,000) minimum bank account balance. On January 27, 2004, EA notified DETM in writing of the impending
expiration of the Master Service Agreement between EA and DETM on March 1,
2004. This correspondence was to notify
DETM of EA’s expiration of its commitment to maintain a $1 million ($1,000,000)
minimum account balance as credit coverage.
The
following illustrates the types of risk EA was exposed to in connection with
the contracts for supply and sales:
• Counterparty risk including the possibility
of the other parties’ failure to fulfill their contractual obligations to EA
such as:
a) Deliverability risk, referring to EA not
being able to serve contracted load due to the supplier’s failure to provide
energy.
b) Transmission risk, indicating EA’s reliance
on utilities, such as the Company, Central Maine Power and Bangor
Hydro-Electric, to physically transport energy to EA’s customers.
c) Credit risk exposure, depending on EA’s
customers’ ability to pay, which may deteriorate during a general economic
downturn or when a commercial customer experiences financial difficulty.
• Market liquidity risk encompasses the risk of
being forced to buy or sell energy on the open market. This would have
occurred (1) if energy had not been available from WS, NB Power or other energy
supply arrangements, while the contracted customer load must still be satisfied
or (2) if the existing customer load deteriorated and NB Power could not buy
the excess power from WS, as contracted.
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• Forecasting risk exposure includes possible
inaccuracy in the estimation of energy supply requirements. One of EA’s
suppliers required a 24-month forecast of load for each commitment to a 1 MW
block of energy. Although there was no penalty for not using all of the
energy, EA could have been assessed a penalty for using more than the amount
contracted.
• Market-based cost risk is exposure to
transactions tied to market indexes, such as the arrangement to sell excess WS
power to NB Power at a current market-indexed rate.
With
the expiration of the SOS arrangement in CMP’s service territory, EA has been
adversely impacted by the decrease in revenues and correspondingly,
earnings. In 2002, EA realized SOS
margin in CMP’s service territory of approximately $5.8 million, which included
the final account settlement discussed above. EA had no SOS activity in
2003. On February 24, 2003, EA
announced its intent to withdraw from the northern Maine market due to the lack
of profitability in that market, the lack of price differentiated electric
products within the Maritimes and Northern Maine Independent System
Administrator markets, and the overall illiquidity of the wholesale power
market, as well as other risk factors.
EA continued to serve its existing contracts in northern Maine through
their expiration on February 27, 2004.
CES sales, primarily in northern Maine, were approximately $6.1 million
in 2003.
EA’s
decision to withdraw from the northern Maine market not only minimized its risk
profile, but EA believed this action would substantially relieve any underlying
concerns that could exist in connection with the issue of employee sharing and EA’s energy marketing activities
within MPS’s service territory. On
February 21, 2003 MPS filed with the MPUC an “Application for Exemption of Chapter
304” to exempt the Company and EA from certain management restrictions that
have arisen due to this aspect of the corporate relationship. (MPUC Docket No. 2003-122). The proceeding is discussed above in Item 3,
“Legal Proceedings” Item 3(iii)(d). In
connection with its announced
intent to withdraw from the retail electricity markets in northern Maine, EA
ceased all of its energy marketing activities in MPS’s service territory as
well as the balance of the State, effective March 1, 2003. Currently,
EA is an inactive subsidiary and management has ceased all active retail CES
activity on behalf of EA within the State of Maine until market conditions, the
availability of supply, the mandate for stringent credit requirements and risk
environment improve. Management will
continue to monitor both U.S. and Canadian deregulated markets to determine the
appropriate timing for possible re-entry into the deregulated retail market.
Reorganization Into Holding Company
On
October 4, 2002, MPS’s Board of Directors authorized MPS to reorganize into a
holding company structure. As a result, MPS became a wholly-owned
subsidiary of MAM, the new holding company.
Me&NB, remained a subsidiary of MPS, and will remain so until all
obligations have terminated, at which time it is proposed the subsidiary may be
dissolved. The ownership of EA was also
transferred to the holding company, MAM. To achieve this corporate
structure, stock in MPS was exchanged for stock in the new holding company
through a “reverse triangular merger.” MPS undertook the reorganization
in order to maintain its focus on its core regulated business, while at the
same time positioning MAM for more diversified growth.
The
reorganization required the approval of the MPUC, acceptance of the S-4A registration
by the U.S. Securities and Exchange Commission, an application under the Public
Utilities Holding Company Act, and approval from the FERC under the Federal
Power Act. Among the first steps authorized by the Board was the filing
of a petition for MPUC approval on October 31, 2002, and the preparation and
filing of documents necessary for other state and federal regulatory
approvals. Certain other regulatory and non-regulatory consents were also
obtained in connection with MPS’s outstanding indebtedness.
Following
the regulatory approval, application and registration process, MPS requested
shareholder approval for the reorganization. Prior to MPS’s Annual
Shareholder Meeting, specific details concerning the holding company were
provided to shareholders. Investor tours and a web cast were held prior
to the 2003 Annual Shareholders Meeting to detail plans and answer specific
shareholder questions.
Subsequent
to its filing, MPS received and responded to several requests for information
from the MPUC and the Office of Public Advocate, an intervenor in the
proceeding, and met on several occasions with interested parties. The parties settled all issues in the
proceeding, and entered a signed Stipulation formally approved by the MPUC on
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March
26, 2003. The text of the MPUC Order,
Docket No. 2002-676 may be viewed as Exhibit 99(ao) of this Form 10-K such
information is incorporated in this section by this reference. MPS also filed, on March 11, 2003, a Form
S-4 Registration Statement with the Securities and Exchange Commission for
“Maine & Maritimes Corporation” the entity designated as “HoldCo” in this
disclosure. The reorganization became
effective June 30, 2003.
At MPS’s Annual Meeting of
Shareholders, held on May 30, 2003, shareholders of MPS voted to approve its plan to create a
holding company structure, under MAM.
Of the shares eligible to vote, 57.07% voted “For” the holding company
proposal, 10.19% voted “Against,” and 32.74% abstained or were “broker no
votes.” The reorganization was
completed by July 1, 2003. No change in
beneficial ownership resulted from the reorganization, which is described in
more detail in the Form S-4/A of MAM filed with the Commission on April 15, 2003
and is incorporated in this section by this reference. The filing is reviewable on the SEC’s
website at “http://www.sec.gov/edgar” or on the MAM Investor Relations page at
http://www.maineandmaritimes.com/ corporate/1373T04_CP.PDF.
Under
the new holding company corporate structure, MPS became a separate subsidiary
of MAM. EA, previously MPS’s
unregulated competitive electricity supply company also became a direct
subsidiary of, MAM. Me&NB, which is
an inactive Canadian company, remained a direct subsidiary of MPS.
Following
the July 1, 2003 completion of the reorganization, shares of MPS common stock
were converted on the books (with no exchange of certificates) into the same
number of shares of common stock of MAM.
The MAM common stock shares are currently traded on the AMEX under the
ticker symbol “MAM.”
Employees
At
the end of 2003, the Company and its subsidiaries had the following full-time
employees:
|
|
|
Employees
|
|
|
|
|
2003
|
|
2002
|
|
|
|
|
|
|
|
|
|
Maine & Maritimes Corporation
|
|
7
|
|
0
|
|
|
Maine Public Service Company
|
|
126
|
|
146
|
|
|
Energy Atlantic, LLC
|
|
5
|
|
9
|
|
|
Maine & New Brunswick Electrical Power
Company, Ltd
|
|
0
|
|
0
|
|
|
Maricor Ltd
|
|
15
|
|
0
|
|
|
Maine & Maritimes Energy Services
Company, dba The Maricor Group
|
|
5
|
|
0
|
|
|
|
|
|
|
|
|
|
Total
|
|
158
|
|
155
|
|
Since
the generating asset sale on June 8, 1999, MPS’s Canadian subsidiary, Me&NB
has had no employees. The Company’s
consolidated payroll costs were $7.1 million for 2003 and $7.3 million for
2002.
Local
1837 of the International Brotherhood of Electrical Workers ratified a
three-year contract with MPS, effective October 1, 2002. The agreement included wage increases of
3.25%, 3.35% and 3.5% over the three-year period of the contract.
In
November 2002, a Voluntary Early Retirement Program (“VERP”) was offered to employees
age fifty-nine and over, with sixteen years or more years of service. Of the thirteen employees eligible for the
program, ten accepted the program and retired effective January 1, 2003. In an effort to control medical insurance
costs, employee contributions increased by approximately 45%, effective January
1, 2003, and plan deductibles were increased.
In addition, all retirees began contributing toward retiree medical
coverage.
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Maine Yankee
MPS
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.
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 MPS’s 5% share would be
approximately $46.5 million. On nine
different occasions dating back to December 1998, Maine Yankee has updated its
estimate of decommissioning costs based on the Settlement. Legislation enacted in Maine in 1997 called
for restructuring the electric utility industry and provided 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, MPS believes that it is
entitled to recover substantially all of its share of such costs from its
customers and, as of December 31, 2003, is carrying on its consolidated balance
sheet a regulatory asset and a corresponding liability in the amount of $17.8
million, which reflects MPS’s 5% share of Maine Yankee’s September 2003 revised
estimate of the remaining decommissioning costs, less actual decommissioning payments
made since then, and discounted by a risk-free interest rate.
The
MPUC, on January 27, 2002, approved a Stipulation providing for the recovery of
stranded investment, for a two-year period from March 1, 2002 until February
29, 2004, which includes MPS’s share of Maine Yankee decommissioning expenses,
Maine Yankee replacement power costs, and the remaining Maine Yankee
investment.
As
of December 31, 2003, deferred fuel of $20.5 million is reflected as a
regulatory asset, which includes the Maine Yankee replacement power costs, as
well as deferred WS fuel costs.
In
accordance with its 1999 FERC rate case settlement, on October 21, 2003, Maine
Yankee filed a revised formula rate schedule with the FERC, proposing an
effective date of January 1, 2004. The
filing contained a revised decommissioning cost estimate and collection
schedule to assure that adequate funds are available to safely and promptly
decommission the Plant and operate and manage the independent spent fuel
storage installation (“ISFSI”). In the filing, Maine Yankee also requested a
change in its billing formula and an increase in the level of collection for
certain post-retirement benefits. To
meet these needs, Maine Yankee proposed to collect an additional $3.77 million
per year over current decommissioning collection levels through October 2008,
exclusive of any income-tax liability, for the decommissioning and spent-fuel
management expense, and to collect from November 2008 through October 2010, the
amounts needed to replenish its Spent Fuel Trust for funds previously used for
ISFSI construction. On December 19,
2003, the FERC issued an order accepting the new rates effective January 1,
2004, subject to refund pending a hearing.
Maine Yankee believes it is entitled to recover the costs underlying the
proposed new rates, but cannot predict the outcome of the rate proceeding.
As
previously reported, in May 2000, Maine Yankee terminated its decommissioning
operations contract with Stone & Webster Engineering Corp. (“Stone &
Webster”) pursuant to the terms of the contract. Stone & Webster disputed Maine Yankee’s grounds for the
termination. In June 2000, Stone &
Webster filed a voluntary petition under Chapter 11 of the United States
Bankruptcy Code with the United States Bankruptcy Court for the District of
Delaware (see Part 1, Item 3, “Legal Proceedings,” Item 3(iii)(e)). Since the contract termination, Maine Yankee
has managed the decommissioning project itself.
In
December 2001, Maine Yankee and Federal Insurance Company (“Federal”) entered
into a settlement agreement resolving litigation between the parties, pursuant
to which Federal paid Maine Yankee $44 million. That amount represented full payment under the performance bond
provided by Federal, plus an additional amount under its payment bond
reflecting certain payments previously made by Maine Yankee to subcontractors
and suppliers who had not been fully paid by Stone & Webster. Maine Yankee deposited the payment in its
decommissioning trust fund to offset past and future expenses resulting from
the failures of Stone & Webster.
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In
addition, Maine Yankee continued to pursue its claim for damages that was
originally filed against Stone & Webster and its then parent corporations
in August 2000, in the Bankruptcy Court in Delaware. After recognizing the payment from Federal, Maine Yankee asserted
a right to recover an additional $21 million in that court from the bankruptcy
estates. After extensive interim proceedings and
negotiations, in the third quarter of 2003, the major parties agreed to a joint
plan of reorganization under which Maine Yankee would have an allowed claim of
$20.3 million against the principal bankrupt estate, subject to certain
contingencies. Under the plan, Maine
Yankee would also have a first lien on any distributions from a related
bankrupt estate in the proceeding on any amount needed to increase its actual
cash recovery to $18.5 million. On
January 13, 2004, Maine Yankee received an initial distribution of $8.4
million, which it deposited in its decommissioning trust fund. The amount of cash that Maine Yankee will
actually recover on the balance of its claim remains contingent on a number of
factors beyond Maine Yankee’s control that affect the amount of bankrupt estate
assets ultimately available to pay the claim.
Maine Yankee has settled its litigation claims against Stone &
Webster’s bankruptcy estate and Envirocare in connection with Stone &
Webster’s bankruptcy proceeding (see Part 1, Item 3, “Legal Proceedings,” Item
3(iii)(e)).
Federal
legislation enacted in 1987 directed the Department of Energy (“DOE”) to
proceed with the studies necessary to develop and operate a permanent
high-level waste (spent fuel) repository at Yucca Mountain, Nevada. The project
has encountered delays, and the DOE has indicated that the permanent disposal
site is not expected to open before 2010, although originally scheduled to open
in 1998.
In
accordance with the process set forth in the legislation, in February 2002, the
Secretary of Energy recommended the Yucca Mountain site to the President for
the development of a nuclear waste repository, and the President then
recommended development of the site to Congress. As provided in the statutory
procedure, the state of Nevada formally objected to the site in April 2002, and
in July 2002, Congress overrode the objection. Construction of the repository
requires the approval of the Nuclear Regulatory Commission (“NRC”), upon
application of the DOE, and after a public adjudicatory hearing, as well as a
second NRC approval after completion of construction to operate the facility.
Maine Yankee cannot predict the timing or results of those proceedings.
In
November 1997, the U.S. Court of Appeals for the District of Columbia Circuit
confirmed the obligation of the DOE under the Nuclear Waste Policy Act of 1982
to take responsibility for spent nuclear fuel from commercial reactors in
January 1998. After an unsuccessful effort by Maine Yankee in the same court to
compel the DOE to take Maine Yankee’s spent fuel, in June 1998, Maine Yankee
filed a claim for money damages in the U.S. Court of Federal Claims for the
costs associated with the DOE’s default. In November 1998, the Court granted
summary judgment in favor of Maine Yankee, ruling the DOE had violated its
contractual obligations, but leaving the amount of damages incurred by Maine
Yankee for later determination by the Court. Since then the parties have
been engaged in extensive discovery and resolution of pre-trial issues in the
damages phase of the proceeding. On June 26, 2003, the Court denied three
motions for summary judgment filed by the DOE and indicated in its order that
final pretrial submissions were to be due at the end of September 2003, with a
trial to follow shortly thereafter.
However, at the end of September, the DOE requested an extension of time
to complete its discovery, which was later granted, extending the discovery
period to February 12, 2004. Maine
Yankee is pursuing its claim for determination of damages vigorously, but
cannot predict the outcome or timing of the determination.
At
the same time, as an interim measure until the DOE meets its contractual
obligation to dispose of Maine Yankee’s spent fuel at Yucca Mountain or
elsewhere, Maine Yankee constructed an ISFSI, utilizing dry-cask storage, on
the Plant site and has completed the process of transferring the spent fuel
from the spent-fuel pool to the individual casks and the casks to the ISFSI.
Maine Yankee’s total cost of maintaining the ISFSI will be substantially
affected by heightened security costs and by the length of time it is required
to operate the ISFSI before the DOE honors its contractual obligation to take
the fuel from the site. Maine Yankee’s current decommissioning costs
estimate is based on an assumption that its operation of the ISFSI will end in
2023, but the actual period of operation and cost may vary.
On
January 15, 2003, Maine Yankee notified NAC International (“NAC”), the
contractor responsible for providing for the fabrication of the spent-fuel
casks and transferring the fuel to the casks and the casks to the ISFSI, that
Maine Yankee was terminating its contract with NAC pursuant to the terms of the
contract. NAC had been experiencing financial difficulties and had requested
relief from the terms of the contract. Maine Yankee believes that NAC had also
failed to perform its contractual obligations in accordance with the terms of
the contract and provide adequate assurance of its ability to do so in the
future. NAC disputed Maine Yankee’s basis for terminating the contract and
served Maine Yankee with a demand to arbitrate the dispute and a request for
damages. Maine Yankee, in turn, filed
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suit
in the U.S. District Court for the District of Maine against NAC, its bonding
company, and its parent guarantor, wherein Maine Yankee sought, among other
things, damages due to NAC’s failure to perform. Maine Yankee also
entered into contracts with the major subcontractors and resumed the transfer
of fuel to the ISFSI under its own management.
In
April 2003, after extensive negotiations, the parties entered into a
comprehensive settlement agreement resolving all the disputed issues and
providing for Maine Yankee to replace NAC in managing the completion of the
fuel-transfer work. The settlement included a payment for $10.4 million
to Maine Yankee to compensate Maine Yankee for higher costs incurred or to be
incurred as a result of NAC’s failure to perform its contractual obligations.
The payment was reflected in Maine Yankee’s second quarter 2003 results.
Although the NAC dispute contributed to a slowdown in the progress of the
fuel transfer work in the first quarter of 2003, since then Maine Yankee has
implemented additional efficiencies and the pace of work has improved to a
point where it has been consistently exceeding the pre-2003 pace. The
transfer of spent fuel to the ISFSI was completed in the first quarter of 2004.
The
Federal Low-Level Radioactive Waste Policy Amendments Act, enacted in 1986,
required states, either alone or in multi-state compacts, to provide for the
disposal of low-level radioactive waste generated within their borders.
The states of Maine, Texas and Vermont entered into a compact for the disposal
of low-level waste over a 30 year period at a then-planned facility in west
Texas.
The
terms of the compact provided that the state of Maine would contribute $25
million, payable (1) in two equal installments, the first after ratification by
Congress and the second upon commencement of operation of the Texas facility,
or (2) alternatively, if agreed by the three states, in accordance with the
schedule for repayment of bonds issued for the development or operation of the
facility. By statute, those costs were to be initially assessed against
Maine Yankee, as the operator of a nuclear power plant in Maine. As required by the 1986 Act, the United
States Congress ratified the compact in September 1998. However, in
October 1998, the Texas Natural Resource Conservation Commission denied a
permit for the proposed west Texas site, and efforts to site such a facility in
Texas were suspended. Maine Yankee is shipping its low-level waste to
other facilities licensed to accept such material.
At
its 2002 session, the Maine legislature enacted legislation providing for the
withdrawal of the state of Maine from the Texas compact pursuant to the terms
of the compact. The legislation cited the 1997 closure of the Maine
Yankee plant and the inability of the state of Texas to cause a disposal
facility to be built in a timely manner under the compact as the reasons for
initiating the withdrawal process. However, in its 2003 session, the
Texas legislature enacted a bill that reactivated the process of siting a
disposal facility in Texas and provides for Texas to seek payment from Maine of
$12.5 million under the compact. By
letter dated September 10, 2003, the Attorney General of Texas requested
payment of $12.5 million from the state of Maine, to which the state of Maine
responded by denying liability. Maine Yankee believes that withdrawal
from the compact by the state of Maine is legally justified, but cannot predict
the results of the Texas legislation on the state of Maine or Maine Yankee or
of any attempt by any party to challenge the state of Maine’s withdrawal from
the compact or to assess Maine Yankee for any payments under the compact.
On
February 28, 2003, the Nuclear Regulatory Commission approved Maine Yankee’s
License Termination Plan (“LTP”). The
LTP was approved without any unexpected conditions. In accordance with the plan accepted by the SEC, Maine Yankee has
started the redemption of its common stock periodically through 2008.
In
June 2001, the FASB issued Statement of Financial Accounting Standards No. 143,
“Accounting for Asset Retirement Obligations” (“Statement 143”). Statement 143
requires an entity to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and to capitalize
the cost by increasing the carrying amount of the related long-lived asset. The
liability is adjusted to its present value periodically over time, and the
capitalized cost is depreciated over the useful life of the related asset. Upon
settlement the entity either settles the obligation at its recorded amount or
incurs a gain or a loss. For rate-regulated entities, any timing differences
between rate recovery and book expense would be deferred as either a regulatory
asset or a regulatory liability. The
Company’s adoption of Statement 143 as of January 1, 2003 did not have a
material effect on its financial position or results of operations. There was
no effect on net income. Statement 143
provides that if the requirements of Statement 71 are met, a regulatory
liability should be recognized for the difference between removal costs
collected in rates and actual costs incurred. As of December 31, 2003, and 2002
accrued removal obligations totaling approximately $4.0 million
Page 45
of 95
and
$3.8 million, respectively, which had previously been embedded within
accumulated depreciation were reclassified as a regulatory liability.
In
December 2003, the FASB issued FASB Interpretation No. 46R, “Consolidation of
Variable Interest Entities, an interpretation of ARB 51” (“FIN 46R”). FIN
46R provides guidance on the identification of entities for which control is
achieved through means other than through voting rights (“variable interest entities”)
and on the determination of when such entities are required to be included in
the consolidated financial statements of the business enterprise that holds an
interest in the variable interest entity. This new model for
consolidation applies to an entity in which either (1) the equity investors do
not have a controlling financial interest or (2) the equity investment at risk
is insufficient to finance that entity’s activities without receiving
additional subordinated financial support from other parties. In addition, FIN
46R requires additional related disclosures. Certain disclosure provisions of
FIN 46R apply to all financial statements issued after January 31, 2003, the
consolidation provisions apply to variable interest entities created after January
31, 2003 and to variable interest entities in which an enterprise obtains an
interest after that date, and the remaining provisions, with the exception of
interest in special purpose entities, apply at the end of the first fiscal year
or interim period ending after March 15, 2004 to variable interest entities in
which an enterprise holds a variable interest that it acquired before February
1, 2003. Application for interest in special purpose entities is required
for periods after December 15, 2003. The adoption of the required
provisions of FIN 46R as of December 31, 2003 did not have a material impact on
the consolidated financial statements. The adoption of the remaining
provisions of FIN 46R is not expected to have a material impact on the consolidated
financial statements.
On
April 30, 2003, the FASB issued Financial Accounting Standards No. 149,
“Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
(“FAS 149”). FAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of Financial Accounting Standards No.
133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS
133”). FAS 149 amends FAS 133 to
reflect decisions that were made: as
part of the process undertaken by the Derivatives Implementation Group (“DIG”),
which necessitated amending FAS 133; in connection with other projects dealing
with financial instruments; and regarding implementation issues related to the
application of the definition of a derivative.
FAS 149 also amends certain other existing pronouncements, which will
result in more consistent reporting of contracts that are derivatives in their
entirety or that contain embedded derivatives that warrant separate
accounting. FAS 149 is effective (1)
for contracts entered into or modified after September 30, 2003, with certain
exceptions, and (2) for hedging relationships designated after June 30. The
guidance is to be applied prospectively.
The adoption of this statement did not have a material impact on the
Company’s financial position or results of operations.
On
May 15, 2003, the FASB issued Financial Accounting Standards No. 150,
“Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity” (“FAS 150”).
FAS 150 changes the accounting for certain financial instruments that,
under previous guidance, could be classified as equity or “mezzanine” equity,
by now requiring those instruments to be classified as liabilities (or assets
in some circumstances) in the statement of financial position. FAS 150 requires disclosure regarding the
terms of those instruments and settlement alternatives. FAS 150 affects an entity’s classification
of the following freestanding instruments: mandatorily redeemable instruments;
financial instruments to repurchase an entity’s own equity instruments;
financial instruments embodying obligations that the issuer must or could
choose to settle by issuing a variable number of its shares or other equity
instruments based solely on (a) a fixed monetary amount known at inception or
(b) something other than changes in its own equity instruments. FAS 150 does not apply to features embedded
in a financial instrument that is not a derivative in its entirety. The guidance in FAS 150 is generally
effective for all financial instruments entered into or modified after May 31,
2003, and is otherwise effective at the beginning of the first interim period
beginning after June 15, 2003. The
adoption of this statement did not have a material impact on the Company.
Regulatory Proceedings
For regulatory proceedings, see Part I, Item 3,
“Legal Proceedings,” which is incorporated in this section by this reference.
Page 46
of 95
PART II
Item 7a. Quantitative and
Qualitative Disclosures about Market Risk
(a) The Company had material interest rate risk until MPS fixed interest
rates on three variable rate debt issues on September 9, 2003 with a derivative
interest rate swap transaction. As
discussed in previous Form 8-K and 10-Q quarterly filings, MPS had partially
mitigated its risk by purchasing a 6% interest rate cap on its two tax-exempt
bonds, the 1996 Series and the 2000 Series, issued on MPS’s behalf by the Maine
Public Utility Financing Bank. The
interest rate cap on the 1996 and 2000 Series expired in November 2003. MPS also purchased a 7% interest rate cap,
which expires in 2008, for MPS’s Taxable Electric Rate Stabilization Revenue
Notes issued in 1998 on its behalf by the Finance Authority of Maine
(“FAME”). Further discussion on these
debt issues and the associated interest rate caps is contained in Item 16(a) of
this Form 10-K, Note 8 to the Consolidated Financial Statements, “Long-Term
Debt,” and is hereby incorporated by this reference. Upon execution of the interest rate swaps on September 9, 2003,
MPS effectively fixed through maturity the rates on the 1996 Series due in 2021
and the 2000 Series due in 2025 at 4.57% and 4.68%, respectively. The rate on the 1998 Notes due in 2008 was
also fixed at 2.79% through maturity.
As of December 31, 2003, the 1996 and 2000 Series and the 1998 FAME
Notes had outstanding balances of $13.9 million, $9.0 million and $8.08
million, respectively. The fixed rates
are higher than the previous floating rates and continue to be as of the date
of this filing. Although incurring no
up-front cost to execute the swaps, MPS is currently incurring increased interest
expenses. However, Management believes
that the fixing of interest rates over the terms of the debt will serve to
protect both shareholders and consumers from what it believes to be inevitable
upward variable interest rate pressures.
See Item 16(a) of this Form 10-K, Note 7 to the Consolidated Financial
Statements, “Accumulated Other Comprehensive Income (Loss),” which is hereby
incorporated by this reference, for a discussion on the impact on MPS’s
financial statements and further description of the interest rate swaps.
(b) The Company’s unregulated marketing subsidiary, EA was previously
engaged in retail and wholesale energy transactions for purposes other than
trading. This activity exposed EA to a
number of risks such as market liquidity, deliverability and credit risk. Prior to withdrawing from retail marketing
activities EA sought to assure that risks were identified, evaluated and
actively managed. These risks are
summarized above under the section “Energy Atlantic Activities.”
Item 8. Financial
Statements and Supplementary Data
(a) The following financial statements and supplementary data are included
in Item 16(a), the Company’s Consolidated Financial Statements, and are
incorporated herein by this reference:
Item 9. Changes In And
Disagreements With Accountants On Accounting and Financial Disclosure
None.
Page 47
of 95
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 2004 Annual Meeting of
Stockholders, which information is incorporated herein by this reference. Certain information regarding executive
officers is set forth below and also in the proxy statement of the registrant
relating to the 2004 Annual Meeting of Stockholders, under “Compliance with
Section 16(a) of the Securities and Exchange Act of 1934,” which information is
incorporated by this reference.
Executive
Officers
The
executive officers of the registrant are as follows:
|
Name
|
|
|
|
Age
|
|
Office
Continuously
Held Since
|
|
|
|
|
|
|
|
|
|
J.
Nicholas Bayne
|
|
President
and Chief Executive Officer
|
|
50
|
|
9/01/02
|
|
|
|
|
|
|
|
|
|
Kurt
A. Tornquist
|
|
Senior
Vice President and Chief Financial Officer, Treasurer
|
|
44
|
|
7/11/03
|
|
|
|
|
|
|
|
|
|
Larry
E. LaPlante
|
|
Vice
President, Chief Accounting Officer, Controller, Clerk, Assistant Treasurer
and Assistant Secretary
|
|
52
|
|
7/11/03
|
|
|
|
|
|
|
|
|
|
John
P. Havrilla
|
|
Vice
President, Business Development And Unregulated Businesses
|
|
45
|
|
11/15/02
|
|
|
|
|
|
|
|
|
|
Scott
L. Sells
|
|
General
Counsel, Secretary and Assistant Clerk
|
|
46
|
|
7/11/03
|
James
Nicholas Bayne was
elected to the position of President and Chief Executive Officer of MPS
effective September 1, 2002. He joined
MPS as President-Elect on March 18, 2002, and became President on May 15,
2002. Prior to joining MPS, Mr. Bayne
served as an executive consultant to the energy, utilities and energy-software
industries. During 2001, he served as
the Chief Executive Officer and as a member of the board of directors for Aspect,
LP, a Houston, Texas-based energy risk management and FASB 133 ASP software
firm, wholly-owned by Koch Ventures/Koch Industries. From 2000 to 2001, he served as Senior Vice President for
Strategic Advisory Services for Energy E-Comm.com, providing consulting
services to the energy and utilities industries. From 1997 to 2000 he served as a member of executive management
and as a member of the board of directors of DukeSolutions, Inc., Duke Energy’s
unregulated retail energy services company, serving as Senior Vice President
for Energy Sales and Operations. Prior
to joining DukeSolutions, Mr. Bayne served as a member of executive management
and Vice President of Marketing, Economic Development and Participant Services
for MEAG Power, the nation’s largest electric generation and transmission joint
action agency headquartered in Atlanta, Georgia. He also served as a member of management of Carolina Power &
Light Company in Raleigh, North Carolina and began his electric utility career
with Central Electric Power Cooperative, Inc. in Columbia, South Carolina.
Kurt A.
Tornquist was elected
to the position of Senior Vice President and Chief Financial Officer,
Treasurer, effective July 11, 2003. He
has been an employee of the Company since July 1, 1992, joining MPS as
Assistant Controller. On June 1, 1994,
Mr. Tornquist was appointed Controller and Assistant Treasurer. On September 2, 2002, Mr. Tornquist was
appointed to the position of Vice President, Corporate Performance and
Development. Prior to joining MPS, Mr.
Tornquist held the position of Manager of Financial Accounting for a major
international paper corporation. Mr.
Tornquist is a graduate of the University of Maine and of Wharton’s Advanced
Management Program and is a Certified Public Accountant.
Page 48
of 95
Larry E.
LaPlante was elected
to the position of Vice President, Chief Accounting Officer, Controller, Clerk,
Assistant Treasurer and Assistant Secretary effective July 11, 2003. On June 1, 1999, Mr. LaPlante was elected to
the position of Vice President, Treasurer and Chief Financial Officer and on
February 15, 2002, appointed Secretary and Clerk of the Company. 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, Administration and Treasurer.
Mr. LaPlante is a graduate of the University of Maine and a Certified
Public Accountant. Prior to joining the
Company, Mr. LaPlante spent ten years in public accounting.
John P.
Havrilla was elected
to the position of Vice President, Business Development and Unregulated
Businesses, effective November 15, 2002.
Mr. Havrilla also holds the position of Chief Operating Officer of The
Maricor Group, the company’s unregulated subsidiary, as well as Chief Operating
Officer of Maricor Ltd, The Maricor Group’s unregulated Canadian
subsidiary. Mr. Havrilla has over
twenty-three years of regulated and unregulated energy experience having served
as Vice President of Strategic and Financial Systems for Duke Energy’s
unregulated retail energy services company.
Prior to joining Duke Power (ultimately Duke Energy) in their mergers
and acquisitions area, he spent sixteen years in positions of increasing
responsibility with New York State Electric & Gas (NYSEG). During his career he has led the successful
acquisition and integration of nine U.S. and Canadian firms. He is a professional engineer licensed in
the states of Maine and New York and graduated from Pennsylvania State
University with a B.S. degree in electrical engineering technology.
Scott L.
Sells, Esquire, of
the law firm of Curtis Thaxter Stevens Broder & Micoleau, LLC, was elected
to the position of General Counsel, Secretary and Assistant Clerk on July 11,
2003. On July 12, 2002 Mr. Sells was
elected as General Counsel. Mr. Sells
has been with Curtis Thaxter for three years, and has been a member for the
entire period. Mr. Sells entered the
practice of law in 1991 as Assistant Attorney General for the state of
Colorado. He then entered private
practice, where his practice emphasized energy, environmental and utility
matters. Mr. Sells then joined Duke
Energy Corporation, in 1998, as Assistant General Counsel. Prior to practicing law, Mr. Sells served as
a geophysicist with Mobil Oil Corporation and the Amoco Production Company,
where he was involved in both domestic and international oil and gas exploration
and development projects. Mr. Sells
received a Bachelor of Science degree in Geology from the University of Rhode
Island and received a Juris Doctorate degree and a Master’s in Business
Administration degree from the University of Denver, where he was an American
Jurisprudence Award recipient.
With
the exception of Mr. Sells, each executive office is a full-time position and
has been the principal occupation of each officer since first elected. All officers were elected to serve until the
next annual election of officers and until their successors shall have been
duly chosen and qualified. The next
annual election of officers will be on May 11, 2004.
There
are no family relationships among executive officers.
Item 11. Executive
Compensation
Information
for this item is set forth in the proxy statement of the registrant relating to
its 2004 Annual Meeting of Stockholders, which information is incorporated
herein by this 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 2004 Annual Meeting of Stockholders, which information is incorporated
herein by this reference.
Item 13. Certain Relationships and Related
Transactions
Not
applicable.
Page 49
of 95
Item 14. Controls and
Procedures
1. Evaluation
of disclosure controls and procedures.
Based on reviews by the Company’s President and Chief Executive Officer
and Senior Vice President and Chief Financial Officer of the Company’s
disclosure controls and procedures, conducted within 90 days of the filing of
this Form 10-K, as evidenced by the certifications appearing at the end of this
Form 10-K, the aforementioned officers have concluded that the controls are
working effectively.
2. Changes
in Internal Controls
There have not been any significant changes in the Company’s internal
controls or in other factors that could significantly offset these controls
subsequent to the date of their evaluation; there were also no corrective
actions with regard to significant deficiencies and material weaknesses.
PART IV
Item 15. Principal
Accountant Services and Fees.
Information
for this item is set forth in the proxy statement of the registrant relating to
its 2004 Annual Meeting of Stockholders, which information is incorporated
herein by this reference.
Item 16. Exhibits,
Financial Statement Schedules and Reports on Form 8-K
(a) (1) Financial Statements
Page 50
of 95
To
The Directors and Shareholders of
Maine
& Maritimes Corporation:
In our opinion, the consolidated financial statements
listed in the index appearing under Item 16(a)(1) on Page 50 present fairly, in
all material respects, the financial position of Maine & Maritimes
Corporation and its subsidiaries at December 31, 2003 and 2002, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2003 in conformity with accounting principles generally
accepted in the United States of America.
In addition, in our opinion, the financial statement schedule listed in
the index appearing under Item 16(a)(2) on Page 82, presents fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements. These financial statements and financial statement schedule are
the responsibility of the Company’s management; our responsibility is to
express an opinion on these financial statements and financial statement
schedule based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, 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 our opinion.
PricewaterhouseCoopers LLP
Boston, MA
February 28, 2004
Page 51
of 95
MAINE & MARITIMES CORPORATION AND
SUBSIDIARIES
Statements
of Consolidated Income
|
|
|
Year Ended
December 31,
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
Regulated
|
|
$
|
31,739,240
|
|
$
|
31,401,082
|
|
$
|
31,780,147
|
|
|
Unregulated
|
|
6,121,269
|
|
6,901,381
|
|
15,771,033
|
|
|
Unregulated SOS Margin
|
|
0
|
|
5,801,670
|
|
2,146,860
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
37,860,509
|
|
44,104,133
|
|
49,698,040
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
Unregulated Energy Supply
|
|
5,219,787
|
|
5,532,679
|
|
14,983,899
|
|
|
Regulated Operation & Maintenance
|
|
12,422,538
|
|
13,044,531
|
|
10,411,460
|
|
|
Unregulated Operation & Maintenance
|
|
2,353,200
|
|
1,654,264
|
|
1,226,418
|
|
|
Depreciation
|
|
2,654,616
|
|
2,420,215
|
|
2,502,034
|
|
|
Amortization of Stranded Costs
|
|
8,761,217
|
|
8,761,233
|
|
9,259,657
|
|
|
Amortization
|
|
205,846
|
|
236,444
|
|
216,842
|
|
|
Taxes Other Than Income
|
|
1,499,109
|
|
1,431,245
|
|
1,344,299
|
|
|
Provision for Income Taxes - Regulated
|
|
1,929,743
|
|
1,908,213
|
|
2,743,193
|
|
|
Provision for (Benefit of) Income Taxes -
Unregulated
|
|
(345,350
|
)
|
2,250,789
|
|
649,813
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating
Expenses
|
|
34,700,706
|
|
37,239,613
|
|
43,337,615
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
3,159,803
|
|
6,864,520
|
|
6,360,425
|
|
|
|
|
|
|
|
|
|
|
|
Other Income
(Deductions)
|
|
|
|
|
|
|
|
|
Equity in Income of Associated Companies
|
|
258,384
|
|
279,514
|
|
299,299
|
|
|
Interest and Dividend Income
|
|
48,709
|
|
157,163
|
|
167,684
|
|
|
Allowance for Equity Funds Used During
Construction
|
|
45,819
|
|
3,463
|
|
85,963
|
|
|
Benefit of (Provision for) Income Taxes
|
|
(42,597
|
)
|
19,366
|
|
46,702
|
|
|
Other - Net
|
|
(362,684
|
)
|
(304,328
|
)
|
(432,208
|
)
|
|
Total
|
|
(52,369
|
)
|
155,178
|
|
167,440
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Interest Charges
|
|
3,107,434
|
|
7,019,698
|
|
6,527,865
|
|
|
|
|
|
|
|
|
|
|
|
Interest Charges
|
|
|
|
|
|
|
|
|
Long-Term Debt and Notes Payable
|
|
1,638,098
|
|
1,626,145
|
|
2,285,711
|
|
|
Less Stranded Costs Carrying Charge
|
|
(1,322,881
|
)
|
(1,076,369
|
)
|
(962,579
|
)
|
|
Less Allowance for Borrowed Funds Used
During Construction
|
|
(13,384
|
)
|
(73,499
|
)
|
(31,794
|
)
|
|
Total
|
|
301,833
|
|
476,277
|
|
1,291,338
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
Available for Common Stock
|
|
$
|
2,805,601
|
|
$
|
6,543,421
|
|
$
|
5,236,527
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted
Earnings Per Share of Common Stock
|
|
$
|
1.78
|
|
$
|
4.16
|
|
$
|
3.33
|
|
|
|
|
|
|
|
|
|
|
|
Average Shares
Outstanding
|
|
1,575,066
|
|
1,573,865
|
|
1,573,294
|
|
See
Notes to Consolidated Financial Statements
Page 52
of 95
MAINE & MARITIMES CORPORATION AND
SUBSIDIARIES
Statements
of Consolidated Cash Flows
|
|
|
Year Ended
December 31,
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
Cash Flow From
Operating Activities
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
2,805,601
|
|
$
|
6,543,421
|
|
$
|
5,236,527
|
|
|
Adjustments to Reconcile Net Income to Net
Cash Provided by (Used For) Operations:
|
|
|
|
|
|
|
|
|
Depreciation
|
|
2,654,616
|
|
2,420,215
|
|
2,502,034
|
|
|
Amortization
|
|
205,846
|
|
236,443
|
|
252,434
|
|
|
Amortization of Seabrook Costs
|
|
1,110,000
|
|
1,110,000
|
|
1,110,000
|
|
|
Amortization of Deferred Gain from Asset
Sale
|
|
(442,777
|
)
|
(2,987,500
|
)
|
(4,863,027
|
)
|
|
Deferred Income Taxes – Net
|
|
3,633,737
|
|
641,044
|
|
872,815
|
|
|
Deferred Investment Tax Credits and Excess
Deferred Income Taxes
|
|
(29,728
|
)
|
(30,521
|
)
|
(32,580
|
)
|
|
Allowance for Funds Used During
Construction
|
|
(59,203
|
)
|
(76,962
|
)
|
(117,757
|
)
|
|
Income on Tax-Exempt Bonds-Restricted Funds
|
|
(8,200
|
)
|
(51,277
|
)
|
(249,928
|
)
|
|
Change in Deferred Regulatory and Debt
Issuance Costs
|
|
(6,829,088
|
)
|
(1,883,614
|
)
|
(548,257
|
)
|
|
Amortization of W/S Upfront Payment
|
|
1,451,000
|
|
1,451,000
|
|
1,451,000
|
|
|
Change in Benefit Obligations
|
|
464,236
|
|
1,263,629
|
|
(173,944
|
)
|
|
Change in Current Assets and Liabilities:
|
|
|
|
|
|
|
|
|
Accounts Receivable and Unbilled Revenue
|
|
(276,782
|
)
|
(85,518
|
)
|
5,860,682
|
|
|
Other Current Assets
|
|
(161,260
|
)
|
109,589
|
|
255,210
|
|
|
Accounts Payable
|
|
(145,170
|
)
|
(1,503,760
|
)
|
(1,414,457
|
)
|
|
Accrued Taxes and Interest
|
|
(268,872
|
)
|
(407,622
|
)
|
(342,082
|
)
|
|
Other Current Liabilities
|
|
(8,259
|
)
|
4,992
|
|
2,537
|
|
|
Other - Net
|
|
(226,666
|
)
|
102,689
|
|
289,079
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Flow
Provided By Operating Activities
|
|
3,869,031
|
|
6,856,248
|
|
10,090,286
|
|
|
Cash Flow From
Financing Activities
|
|
|
|
|
|
|
|
|
Dividend Payments
|
|
(2,930,788
|
)
|
(2,234,678
|
)
|
(2,060,821
|
)
|
|
Retirements of Long-Term Debt
|
|
(3,085,000
|
)
|
(1,175,000
|
)
|
(1,050,000
|
)
|
|
|
|
|
|
|
|
|
|
|
Short-Term Borrowings, Net
|
|
3,349,019
|
|
(1,150,000
|
)
|
(950,000
|
)
|
|
Net Cash Flow Used
For Financing Activities
|
|
(2,666,769
|
)
|
(4,559,678
|
)
|
(4,060,821
|
)
|
|
Cash Flow From
Investing Activities
|
|
|
|
|
|
|
|
|
Drawdown from Tax-Exempt Bond Trust
|
|
2,064,224
|
|
3,717,467
|
|
2,012,353
|
|
|
Additional Proceeds from Sale of Generating
Assets in 1999
|
|
—
|
|
—
|
|
1,050,679
|
|
|
Stock Redemption from Associated Company
|
|
524,724
|
|
375,277
|
|
499,484
|
|
|
Acquisition, Net of Cash Acquired
|
|
(526,502
|
)
|
—
|
|
—
|
|
|
Investment in Electric Plant
|
|
(4,876,945
|
)
|
(5,928,431
|
)
|
(4,707,152
|
)
|
|
Net Cash Flow Used
For Investing Activities
|
|
(2,814,499
|
)
|
(1,835,687
|
)
|
(1,144,636
|
)
|
|
Increase (Decrease)
in Cash and Cash Equivalents
|
|
(1,612,237
|
)
|
460,883
|
|
4,884,829
|
|
|
Cash and Cash
Equivalents at Beginning of Period
|
|
5,956,422
|
|
5,495,539
|
|
610,710
|
|
|
Cash and Cash
Equivalents at End of Period
|
|
$
|
4,344,185
|
|
$
|
5,956,422
|
|
$
|
5,495,539
|
|
|
Supplemental Disclosure of Cash Flow
Information:
|
|
|
|
|
|
|
|
|
Cash Paid During the Period For:
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
1,253,496
|
|
$
|
1,119,239
|
|
$
|
2,499,080
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes (2001 is net of tax refunds of
$200,000)
|
|
$
|
785,088
|
|
$
|
4,028,408
|
|
$
|
1,499,654
|
|
|
Non-Cash Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Value of stock issued for acquisition
|
|
$
|
193,570
|
|
—
|
|
—
|
|
See
Notes to Consolidated Financial Statements
Page 53
of 95
MAINE & MARITIMES CORPORATION AND SUBSIDIARIES
Consolidated
Balance Sheets
|
|
|
December
31,
|
|
|
|
|
2003
|
|
2002
|
|
|
ASSETS
|
|
|
|
|
|
|
Utility Plant
|
|
|
|
|
|
|
Electric Plant in Service
|
|
$
|
92,055,256
|
|
$
|
88,072,501
|
|
|
Less Accumulated Depreciation
|
|
37,618,250
|
|
35,583,430
|
|
|
Net Electric Plant in Service
|
|
54,437,006
|
|
52,489,071
|
|
|
Construction Work-in-Progress
|
|
7,752
|
|
95,921
|
|
|
Total
|
|
54,444,758
|
|
52,584,992
|
|
|
|
|
|
|
|
|
|
Investment in
Associated Companies
|
|
2,729,137
|
|
3,397,544
|
|
|
|
|
|
|
|
|
|
Net Utility Plant
and Investments in Associated Companies
|
|
57,173,895
|
|
55,982,536
|
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
Cash and Cash Equivalents
|
|
4,344,185
|
|
5,956,422
|
|
|
Accounts Receivable (less allowance for
uncollectible accounts of $235,682 in 2003 and $213,882 in 2002)
|
|
6,032,244
|
|
5,429,383
|
|
|
Unbilled Revenue
|
|
1,198,470
|
|
1,293,953
|
|
|
Inventory
|
|
694,698
|
|
561,829
|
|
|
Income Tax Refund Receivable
|
|
229,258
|
|
216,810
|
|
|
Prepayments
|
|
361,180
|
|
261,614
|
|
|
Total
|
|
12,860,035
|
|
13,720,011
|
|
|
|
|
|
|
|
|
|
Regulatory Assets:
|
|
|
|
|
|
|
Uncollected Maine Yankee Decommissioning
Costs
|
|
17,771,344
|
|
22,153,501
|
|
|
Recoverable Seabrook Costs (less
accumulated amortization and write-offs in 2003, $39,298,399 and 2002,
$38,188,399)
|
|
13,888,611
|
|
14,998,611
|
|
|
Regulatory Assets - SFAS 109 & 106
|
|
6,648,074
|
|
7,161,604
|
|
|
Deferred Fuel and Purchased Energy Costs
|
|
20,495,481
|
|
13,132,485
|
|
|
Regulatory Asset - Power Purchase Agreement
Restructuring
|
|
4,352,750
|
|
5,803,750
|
|
|
Unamortized Premium on Early Retirement of
Debt
|
|
1,497,741
|
|
1,709,493
|
|
|
Deferred Regulatory Costs, less accumulated
amortization
|
|
1,392,118
|
|
1,409,092
|
|
|
|
|
|
|
|
|
|
Total
|
|
66,046,119
|
|
66,368,536
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
Intangible Assets
|
|
137,648
|
|
—
|
|
|
Goodwill
|
|
404,125
|
|
—
|
|
|
Unamortized Debt Issuance Costs
|
|
625,075
|
|
823,213
|
|
|
Restricted Investment (at cost, which
approximates market)
|
|
2,378,492
|
|
4,436,879
|
|
|
Miscellaneous
|
|
1,643,376
|
|
654,981
|
|
|
|
|
|
|
|
|
|
Total
|
|
5,188,716
|
|
5,915,073
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
141,268,765
|
|
$
|
141,986,156
|
|
See
Notes to Consolidated Financial Statements
Page 54
of 95
MAINE & MARITIMES CORPORATION AND SUBSIDIARIES
Capitalization
and Liabilities
|
|
|
December
31,
|
|
|
|
|
2003
|
|
2002
|
|
|
Capitalization (see
accompanying statements):
|
|
|
|
|
|
|
Common Shareholders’ Equity
|
|
$
|
46,984,490
|
|
$
|
47,029,071
|
|
|
Long-Term Debt
|
|
29,230,000
|
|
30,680,000
|
|
|
Total
|
|
76,214,490
|
|
77,709,071
|
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
Long-Term Debt Due Within One Year
|
|
1,450,000
|
|
3,085,000
|
|
|
Notes Payable to Banks
|
|
6,200,000
|
|
2,800,000
|
|
|
Accounts Payable
|
|
3,928,235
|
|
3,523,506
|
|
|
Accounts Payable - Associated Companies
|
|
27,589
|
|
248,224
|
|
|
Accrued Employee Benefits
|
|
1,013,342
|
|
1,336,087
|
|
|
Dividends Declared
|
|
—
|
|
582,423
|
|
|
Customer Deposits
|
|
18,944
|
|
27,202
|
|
|
Taxes Accrued
|
|
20,290
|
|
18,349
|
|
|
Interest Accrued
|
|
34,931
|
|
179,745
|
|
|
Total
|
|
12,693,331
|
|
11,800,536
|
|
|
|
|
|
|
|
|
|
Deferred Credits
and Other Liabilities:
|
|
|
|
|
|
|
Accrued Removal Obligations
|
|
4,015,121
|
|
3,848,594
|
|
|
Carrying Value of Interest Rate Hedge
|
|
1,185,000
|
|
—
|
|
|
Uncollected Maine Yankee Decommissioning
Costs
|
|
17,771,344
|
|
22,153,501
|
|
|
Income Taxes
|
|
25,044,348
|
|
22,270,998
|
|
|
Accrued Post-retirement Benefits and
Pension Costs
|
|
3,461,572
|
|
3,122,030
|
|
|
Investment Tax Credits
|
|
159,345
|
|
189,073
|
|
|
Deferred Gain & Related
Accounts-Generating Asset Sale
|
|
0
|
|
468,440
|
|
|
Miscellaneous
|
|
724,214
|
|
423,913
|
|
|
Total
|
|
52,360,944
|
|
52,476,549
|
|
|
|
|
|
|
|
|
|
Commitments,
Contingencies and Regulatory Matters (Note 12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Capitalization and Liabilities
|
|
$
|
141,268,765
|
|
$
|
141,986,156
|
|
See Notes to Consolidated Financial Statements
Page 55
of 95
MAINE & MARITIMES CORPORATION AND
SUBSIDIARIES
Statement
of Consolidated Common Shareholders’ Equity
|
|
|
Number of
Shares
|
|
Par Value
Issued
|
|
Paid-In
Capital
|
|
Retained
Earnings
|
|
Treasury
Stock
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issued
|
|
Treasury
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2000
|
|
1,867,250
|
|
(294,352
|
)
|
$
|
13,070,750
|
|
$
|
39,668
|
|
$
|
33,097,712
|
|
$
|
(6,622,179
|
)
|
—
|
|
$
|
39,585,951
|
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
5,236,527
|
|
|
|
|
|
5,236,527
|
|
|
Dividend ($1.34 per share)
|
|
|
|
|
|
|
|
|
|
(2,108,222
|
)
|
|
|
|
|
(2,108,222
|
)
|
|
Treasury Stock Reissued
|
|
|
|
612
|
|
—
|
|
3,794
|
|
|
|
13,099
|
|
—
|
|
16,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2001
|
|
1,867,250
|
|
(293,740
|
)
|
13,070,750
|
|
43,462
|
|
36,226,017
|
|
(6,609,080
|
)
|
—
|
|
42,731,149
|
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
6,543,421
|
|
|
|
|
|
6,543,421
|
|
|
Dividend ($1.44 per share)
|
|
|
|
|
|
|
|
|
|
(2,266,372
|
)
|
|
|
|
|
(2,266,372
|
)
|
|
Treasury Stock Reissued
|
|
|
|
605
|
|
—
|
|
7,869
|
|
|
|
13,004
|
|
|
|
20,873
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2002
|
|
1,867,250
|
|
(293,135
|
)
|
13,070,750
|
|
51,331
|
|
40,503,066
|
|
(6,596,076
|
)
|
—
|
|
47,029,071
|
|
|
Formation of MAM June 30, 2003
|
|
(292,668
|
)
|
292,668
|
|
(2,048,676
|
)
|
(52,891
|
)
|
(4,484,305
|
)
|
6,585,872
|
|
—
|
|
—
|
|
|
New Stock Issued
|
|
5,930
|
|
467
|
|
41,510
|
|
167,285
|
|
|
|
10,204
|
|
|
|
218,999
|
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
2,805,601
|
|
|
|
|
|
2,805,601
|
|
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Value of Foreign Exchange Translation
Gain (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,815
|
)
|
(8,815
|
)
|
|
Interest Rate Hedge, Net of Tax Benefit of
$473,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(712,000
|
)
|
(712,000
|
)
|
|
Dividend ($1.49 per share)
|
|
|
|
|
|
|
|
|
|
(2,348,366
|
)
|
|
|
|
|
(2,348,366
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2003
|
|
1,580,512
|
|
—
|
|
$
|
11,063,584
|
|
$
|
165,725
|
|
$
|
36,475,996
|
|
$
|
—
|
|
$
|
(720,815
|
)
|
$
|
46,984,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
Notes to Consolidated Financial Statements.
Page 56
of 95
MAINE & MARITIMES CORPORATION AND
SUBSIDIARIES
Statement
of Long-Term Debt
|
(Maine Public Service Company)
|
|
2003
|
|
2002
|
|
|
First Mortgage and Collateral Trust Bonds:
|
|
|
|
|
|
|
7.95% Due Serially through 2003-Interest
Payable, March 1 and September 1
|
|
$
|
—
|
|
$
|
1,800,000
|
|
|
|
|
|
|
|
|
|
Maine Public Utility Financing Bank, Public
Utility Revenue Bonds:
|
|
|
|
|
|
|
Refunding Series 1996: Due 2021 - Variable Interest Payable
Monthly
(1.20% as of December 31, 2003)
|
|
13,600,000
|
|
13,600,000
|
|
|
Series 2000: Due 2025 - Variable Interest Payable Monthly
(1.20% as of December 31, 2003)
|
|
9,000,000
|
|
9,000,000
|
|
|
|
|
|
|
|
|
|
Finance Authority of Maine:
|
|
|
|
|
|
|
1998 Taxable Electric Rate Stabilization
|
|
|
|
|
|
|
Revenue Notes: Due 2008 - Variable Interest
Payable Monthly
(1.15% as of December 31, 2003)
|
|
8,080,000
|
|
9,365,000
|
|
|
|
|
|
|
|
|
|
Total Outstanding
|
|
30,680,000
|
|
33,765,000
|
|
|
|
|
|
|
|
|
|
Less - Amount Due Within One Year
|
|
1,450,000
|
|
3,085,000
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
29,230,000
|
|
$
|
30,680,000
|
|
Current
Maturities and Redemption Requirements for the Succeeding Five Years and
Thereafter Are as Follows:
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
2004
|
|
$
|
1,450,000
|
|
|
2005
|
|
$
|
1,625,000
|
|
|
2006
|
|
$
|
1,830,000
|
|
|
2007
|
|
$
|
2,055,000
|
|
|
2008
|
|
$
|
1,120,000
|
|
|
|
|
|
|
|
Thereafter
|
|
$
|
22,600,000
|
|
See
Notes to Consolidated Financial Statements.
Page 57
of 95
NOTES TO
CONSOLIDATED
FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Consolidation and Basis of Presentation
The
accompanying consolidated financial statements include the accounts of Maine
& Maritimes Corporation (the “Company” or “MAM”) and the following
wholly-owned active subsidiaries and affiliates:
• Maine Public Service Company (“MPS”),
regulated transmission and distribution company and its wholly-owned inactive
Canadian subsidiary, Maine and New Brunswick Electrical Power Company, Limited,
(“Me&NB”);
• Energy Atlantic, LLC (“EA”), unregulated
competitive electricity marketing subsidiary, which was owned by MPS until June
30, 2003;
• Maine & Maritimes Energy Services Company
(“MAMES”) dba “The Maricor Group” and its wholly-owned Canadian subsidiary,
Maricor, Ltd, (“Maricor”) providing energy management and engineering services.
MAM,
a holding company organized effective June 30, 2003, owns all of the common
stock of MPS. All of the shares of MPS
common stock were converted into an equal number of shares of MAM common stock,
which are listed on the American Stock Exchange under the symbol MAM. The reorganization was approved by MPS’s shareholders
at the annual meeting on May 30, 2003.
The U.S. Securities and Exchange Commission (“SEC”) had previously
accepted MAM’s S-4A Registration Statement for registration and other
appropriate state and federal regulatory agencies issued the necessary
approvals on various dates in 2003.
Amounts shown for 2002 and 2001 were reported by MPS. MPS also reported amounts in the first three
months of 2003.
MAMES
and Maricor were organized on November 6, 2003, and November 12, 2003,
respectively. On December 1, 2003,
Maricor acquired a mechanical and electrical engineering firm located in New
Brunswick, Canada.
All
inter-company transactions between MAM and it subsidiaries have been eliminated
in consolidation.
The
financial statements of the Company were prepared in accordance with accounting
principles generally accepted in the United States of America.
Regulations
MPS
is subject to the regulatory authority of the Maine Public Utilities Commission
(“MPUC”) and 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.
Estimates
The
preparation of financial statements in conformity with generally accepted
accounting principles asserted in the United States of America 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 Me&NB and Maricor is the U.S. dollar. Accordingly, translation gains and losses
are included in other income. Income
and expenses are translated at rates of exchange prevailing at the time the
income is earned or the expenses are incurred.
Assets and liabilities are translated at year-end exchange rates.
Deferred Fuel and Purchased Energy Costs
Certain
Wheelabrator-Sherman (“WS”) fuel costs and the sharing provisions for Maine
Yankee replacement power costs were deferred for future recovery as defined in
MPS’s rate plan until March 1, 2000.
All other fuel and purchased power costs were expensed as incurred. These costs are currently being recovered in
rates and the related deferred asset is being amortized, accordingly. Beginning March 1, 2002, the excess of the
cost over the sales price of WS fuel is being deferred. The resulting deferred asset is expected to
be collected in future rates as approved by the MPUC. See Note 12, “Commitments, Contingencies and Regulatory Matters,”
regarding MPUC rate orders on the recovery of stranded costs.
Regulatory Assets and Liabilities
Pursuant
to Statement of Financial Accounting Standards No. 71, Accounting for the
Effects of Certain Types of Regulation, the Company capitalizes, as regulatory
assets, incurred and accrued costs that are probable of recovery in future
electric rates. It also records, as regulatory liabilities, obligations to
refund previously collected revenue or to spend revenue collected from
customers on future costs.
Unfunded
future income taxes and deferred income taxes are amortized as the related
temporary differences reverse. Unamortized loss on debt re-acquisitions is
amortized over the lives of the related debt issues. Nuclear plant obligations,
demand-side management program
Page 58
of 95
costs,
gain on sale of generation assets, other regulatory assets and other regulatory
liabilities are amortized over various periods in accordance with MPS’s current
rate plans. MPS earns a return on substantially all regulatory assets for which
funds have been spent.
The
Company believes that MPS’s 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, 2003, $66.0
million of regulatory assets remained on MPS’s books. These assets will be amortized over various periods in accordance
with MPUC approved rate orders.
Revenue Recognition
Operating
revenues include MPS’s sales billed on a cycle billing basis and estimated
unbilled revenues for electric service rendered prior to the normal billing
cycle. Operating revenues also include
EA’s Competitive Electricity Supply (“CES”) sales, since CES activity is
recorded on a gross basis to include the related revenues and purchased power
expenses. CES sales are recorded in
this manner because EA negotiated the price directly with the customer,
maintains customer service responsibility and has collection risk. For Standard Offer Service (“SOS”), revenues
were received and expenses were paid directly by an escrow agent which was
controlled by Engage Energy America, LLC (“Engage”). EA received a percentage of the net profit from the sale of
energy. The utilities bore SOS account
collection risk, as they were required to remit the amounts billed 26 days
after the billing date to the escrow account mentioned above and maintain the
billing and customer service relationship.
EA recorded the accrued net margin of the SOS activity as revenue in the
financial statements. Additionally,
EA’s activity has been accounted for as non-trading since management has
determined it does not meet the definition of a trader as defined in EITF
98-10, as modified by EITF 02-03.
In
July, 2000, MPS began recording the difference between the approved tariff rate
for two large industrial customers and their current special discount rates,
under contracts approved by the MPUC, as accrued revenue. The resulting deferred asset will be
subsequently collected in rates as approved by the MPUC, and during 2003 and
2002, $280,000 and $233,000 were recognized as stranded costs. During 2002 and 2001, $200,000 and $961,000,
respectively, were recognized as revenue as flexible pricing adjustments, as
described in Note 12, “Commitments, Contingencies and Regulatory Matters — MPUC
Approves Elements of Rates Effective March 1, 2000, and MPUC Approves Stranded
Cost Revenue Requirements Effective March 1, 2002.”
Utility Plant
Utility
plant for MPS 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
is charged to accumulated depreciation.
The cost of removal less salvage is charged to Accrued Removal
Obligations. The cost of maintenance
and repairs, including replacement of minor items of property, are charged to
maintenance expense as incurred. MPS’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 expense at the time such disallowance is probable.
Depreciation and Amortization
Utility
plant depreciation is provided on composite basis using the straight-line
method, based on rates approved by the MPUC and the FERC. The composite depreciation rate, expressed
as a percentage of average depreciable plant in service, was approximately
3.20%, 3.10% and 3.37% for 2003, 2002, and 2001, 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 (See Note 12, “Commitments, Contingencies and
Regulatory Matters – Seabrook Nuclear Power Project”).
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.
MPS
has deferred investment tax credits and amortizes the credits over the
remaining estimated useful life of the related utility plant.
MPS
records regulatory assets or liabilities related to certain deferred tax
liabilities or assets, representing its expectation that, consistent with
current and expected ratemaking, these taxes will be recovered from or returned
to customers through future rates.
Investments in Associated Companies
MPS
records its investments in Associated Companies (see Note 5, “Investments in
Associated Companies”) using the equity method.
Pledged Assets
The
common stock of Me&NB is pledged as additional collateral for the first and
second mortgage and collateral trust bonds of MPS.
Page 59
of 95
Inventory
Inventory
for MPS is stated at average cost.
Cash and Cash Equivalents
For
purposes of the Statements of Consolidated Cash Flows, the Company considers
all highly liquid securities with a maturity, when purchased, of three months
or less to be cash equivalents.
Goodwill
The
excess of the cost over fair value of net assets of purchased businesses is
recorded as goodwill. The Company
evaluates the carrying value of goodwill for impairment at least annually and on
an interim basis if there are indications that goodwill might be impaired. Any
impairments would be recognized when the fair value of goodwill is less than
its carrying value.
Financial Instruments
MPS
has certain financial instruments, interest rate caps and swaps, on three
variable rate long-term debt issues that qualify as derivatives. Interest rate caps involve the exchange of
cash for a cap on the interest rate MPS can be charged. Interest rate swaps involve the exchange of
cash and the exchange of a variable rate payment for a fixed rate payment. On January 1, 2001, the Company adopted
Statement of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (“SFAS 133”), as amended by SFAS 137, 138
and 149, which establishes accounting and reporting standards for derivative
instruments and for hedging activities.
SFAS 133 requires that an entity recognize derivatives as either assets
or liabilities on the balance sheet and measure those instruments at fair
value. The accounting for changes in
the fair value of the derivative depends on the intended use of the derivative
and the resulting designation. See Note
7, “Accumulated Other Comprehensive Income (Loss)” for additional disclosure
regarding the treatment of these interest rate instruments.
Stock Option Plan
At December 31, 2003, the Company had one stock-based employee
compensation plan, which is described more fully in Note 9, “Stock Compensation
Plan.” The Company accounts for this
plan in accordance with the expense provisions of Statement of Financial
Accounting Standards (“SFAS”) No. 123 “Accounting for Stock Based
Compensation.”
Reclassifications
Certain
reclassifications have been made to the 2002 and 2001 financial statement
amounts in order to conform to the 2003 presentation.
Earnings Per Share
Basic
earnings per share (“EPS”) is determined by dividing net income by the
weighted-average number of shares of common stock outstanding during the
period. The weighted-average common
shares outstanding for diluted EPS include the incremental effect of stock
options issued. There was no difference
between basic and diluted earnings per share for the three years in the period
ended December 31, 2003. Options to
purchase shares of common stock of 5,250 shares at $30.45 per share granted
June 1, 2002 and 5,250 shares at $32.51 per share granted June 1, 2003. These options to purchase shares were not
included in the computation of diluted EPS because the options’ exercise price
was approximately equal to the market price of the common shares and,
therefore, the effect would be anti-dilutive.
The options, which expire on May 30, 2012 and May 30, 2013,
respectively, were still outstanding at the end of year 2003.
Accounting Pronouncements
In
June 2001, the FASB issued Statement of Financial Accounting Standards No. 143,
“Accounting for Asset Retirement Obligations” (“Statement 143”). Statement 143 requires an entity to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and to capitalize the cost by increasing the carrying
amount of the related long-lived asset. The liability is adjusted to its
present value periodically over time, and the capitalized cost is depreciated
over the useful life of the related asset. Upon settlement the entity either
settles the obligation at its recorded amount or incurs a gain or a loss. For
rate-regulated entities, any timing differences between rate recovery and book
expense would be deferred as either a regulatory asset or a regulatory
liability. The Company’s adoption of
Statement 143 as of January 1, 2003 did not have a material effect on its
financial position or results of operations. There was no effect on net income. Statement 143 provides that if the requirements
of Statement 71 are met, a regulatory liability should be recognized for the
difference between removal costs collected in rates and actual costs incurred.
As of December 31, 2003 and 2002, accrued removal obligations totaling
approximately $4.0 million and $3.8 million, respectively, which had previously
been embedded within accumulated depreciation were reclassified as a regulatory
liability.
In December 2003, the FASB issued FASB Interpretation No. 46R,
“Consolidation of Variable Interest Entities, an interpretation of ARB 51”
(“FIN 46R”). FIN 46R provides guidance on the identification of entities
for which control is achieved through means other than through voting rights
(“variable interest entities”) and on the determination of when such entities
are required to be included in the consolidated financial statements of the
business enterprise that holds an interest in the variable interest entity.
This new model for consolidation applies to an entity in which either (1)
the equity investors do not have a controlling financial interest or (2) the
equity investment at risk is insufficient to finance that entity’s activities
without receiving additional subordinated financial support from other parties.
In addition, FIN 46R requires additional related disclosures. Certain
disclosure provisions of FIN 46R apply to all financial statements issued after
January 31, 2003, the consolidation provisions apply to variable interest
entities created after January 31, 2003 and to variable interest entities in
which an enterprise obtains an interest after that date, and the remaining
provisions, with the exception of interest in special purpose entities, apply
at the end of the first fiscal year or interim period ending after March 15,
2004 to variable interest entities in which an
Page 60
of 95
enterprise holds a variable interest that it acquired before February
1, 2003. Application for interest in special purpose entities is required
for periods after December 15, 2003. The adoption of the required
provisions of FIN 46R as of December 31, 2003 did not have a material impact on
the consolidated financial statements. The adoption of the remaining
provisions of FIN 46R is not expected to have a material impact on the
consolidated financial statements.
On
April 30, 2003, the FASB issued Financial Accounting Standards No. 149,
“Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
(“FAS 149”). FAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of Financial Accounting Standards No.
133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS
133”). FAS 149 amends FAS 133 to
reflect decisions that were made: as
part of the process undertaken by the Derivatives Implementation Group (“DIG”),
which necessitated amending FAS 133; in connection with other projects dealing
with financial instruments; and regarding implementation issues related to the
application of the definition of a derivative.
FAS 149 also amends certain other existing pronouncements, which will
result in more consistent reporting of contracts that are derivatives in their
entirety or that contain embedded derivatives that warrant separate
accounting. FAS 149 is effective (1)
for contracts entered into or modified after September 30, 2003, with certain
exceptions, and (2) for hedging relationships designated after June 30. The
guidance is to be applied prospectively.
The adoption of this statement did not have a material impact on the
Company’s financial position or results of operations.
On
May 15, 2003, the FASB issued Financial Accounting Standards No. 150,
“Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity” (“FAS 150”).
FAS 150 changes the accounting for certain financial instruments that,
under previous guidance, could be classified as equity or “mezzanine” equity,
by now requiring those instruments to be classified as liabilities (or assets
in some circumstances) in the statement of financial position. FAS 150 requires disclosure regarding the
terms of those instruments and settlement alternatives. FAS 150 affects an entity’s classification
of the following freestanding instruments: mandatorily redeemable instruments;
financial instruments to repurchase an entity’s own equity instruments;
financial instruments embodying obligations that the issuer must or could
choose to settle by issuing a variable number of its shares or other equity
instruments based solely on (a) a fixed monetary amount known at inception or
(b) something other than changes in its own equity instruments. FAS 150 does not apply to features embedded
in a financial instrument that is not a derivative in its entirety. The guidance in FAS 150 is generally
effective for all financial instruments entered into or modified after May 31,
2003, and is otherwise effective at the beginning of the first interim period
beginning after June 15, 2003. The
adoption of this statement did not have a material impact on the Company.
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 on MPS regulated activities and unregulated
activities for MAM, MAMES, Me&NB and Maricor. The tax effect of items not included in rate base or normal
operating activities is allocated as “Other Income (Deductions).”
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
Current income taxes
|
|
$
|
760,532
|
|
$
|
3,473,150
|
|
$
|
2,489,429
|
|
|
Deferred income taxes
|
|
896,186
|
|
697,007
|
|
889,455
|
|
|
Investment credits, net
|
|
(29,728
|
)
|
(30,521
|
)
|
(32,580
|
)
|
|
Total income taxes
|
|
$
|
1,626,990
|
|
$
|
4,139,636
|
|
$
|
3,346,304
|
|
|
Allocated to:
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
|
|
|
|
|
|
• Regulated
|
|
$
|
1,929,743
|
|
$
|
1,908,213
|
|
$
|
2,743,193
|
|
|
• Unregulated
|
|
(345,350
|
)
|
2,250,789
|
|
649,813
|
|
|
Total
|
|
1,584,393
|
|
4,159,002
|
|
3,393,006
|
|
|
Other income
|
|
42,597
|
|
(19,366
|
)
|
(46,702
|
)
|
|
Total
|
|
$
|
1,626,990
|
|
$
|
4,139,636
|
|
$
|
3,346,304
|
|
The effective income tax rates differ from the U.S. statutory rate as follows:
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
Statutory rate
|
|
34.0
|
%
|
34.0
|
%
|
34.0
|
%
|
|
Holding Company Formation
|
|
2.2
|
|
—
|
|
—-
|
|
|
Amortization of recoverable Seabrook costs
|
|
4.9
|
|
2.1
|
|
2.6
|
|
|
State income taxes
|
|
5.2
|
|
5.6
|
|
5.6
|
|
|
Carrying Charge
|
|
(10.2
|
)
|
(3.4
|
)
|
(3.8
|
)
|
|
Other
|
|
.6
|
|
.5
|
|
.6
|
|
|
Effective rate
|
|
36.7
|
%
|
38.8
|
%
|
39.0
|
%
|
Page 61
of 95
The
elements of deferred income tax expense (credit) are as follows (dollars in
thousands):
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
Temporary Differences at Statutory Rates:
|
|
|
|
|
|
|
|
|
Seabrook – costs
|
|
$
|
(186
|
)
|
$
|
(186
|
)
|
$
|
(186
|
)
|
|
Liberalized depreciation
|
|
467
|
|
289
|
|
118
|
|
|
Deferred fuel
|
|
1,420
|
|
22
|
|
(332
|
)
|
|
Deferred regulatory expense
|
|
239
|
|
(25
|
)
|
(27
|
)
|
|
Flexible pricing revenue
|
|
(104
|
)
|
32
|
|
383
|
|
|
Accrued pension and post-retirement
benefits
|
|
(132
|
)
|
(404
|
)
|
101
|
|
|
Wheelabrator-Sherman power purchase
restructuring
|
|
(579
|
)
|
(579
|
)
|
(579
|
)
|
|
Generating Asset Sale
|
|
178
|
|
1,187
|
|
1,538
|
|
|
Reacquired debt
|
|
(85
|
)
|
(85
|
)
|
(101
|
)
|
|
Maine Yankee NEIL Refund
|
|
—
|
|
401
|
|
—
|
|
|
Other
|
|
(322
|
)
|
45
|
|
(26
|
)
|
|
Total temporary differences - statutory
rates
|
|
$
|
896
|
|
$
|
697
|
|
$
|
889
|
|
The
Company has not accrued U.S. income taxes on the undistributed earnings of
Me&NB, as the withholding taxes due on the distribution of any remaining
amount would be principally offset by foreign tax credits. No dividends were received from Me&NB in
2003, 2002 or 2001.
The
following summarizes accumulated deferred income tax (assets) and liabilities
established on temporary differences under SFAS 109 as of December 31, 2003 and
2002:
|
|
|
(Dollars
in Thousands)
|
|
|
|
|
2003
|
|
2002
|
|
|
|
|
|
|
|
|
|
Seabrook
|
|
$
|
7,577
|
|
$
|
8,428
|
|
|
Property
|
|
7,784
|
|
7,084
|
|
|
Flexible pricing revenue
|
|
608
|
|
567
|
|
|
Deferred fuel
|
|
8,176
|
|
4,162
|
|
|
Generating asset sale
|
|
—
|
|
(178
|
)
|
|
Wheelabrator-Sherman up-front payment
|
|
1,736
|
|
2,315
|
|
|
Pension and post-retirement benefits
|
|
(610)
|
|
(478
|
)
|
|
OCI-Interest Rate Hedge
|
|
(473
|
)
|
—
|
|
|
Other
|
|
246
|
|
371
|
|
|
Net accumulated deferred income taxes
|
|
$
|
25,044
|
|
$
|
22,271
|
|
3. ENERGY ATLANTIC
EA’s net loss for 2003 was $116,000 compared to net
income of $3,444,000 and $897,000 for 2002 and 2001, respectively. EA’s loss in 2003 reflects the gradual
termination of service as contracts expire in northern Maine. The current standard offer pricing in Maine,
the lack of wholesale choices and liquidity within northern Maine, and the
increased credit requirements associated with acquiring wholesale electricity
supply have hampered EA in competing for sales. The Company maintains a conservative risk management philosophy
and has limited the transactions that EA can undertake as a buyer or seller in
order to limit and mitigate potential transaction risk exposures. EA earnings for 2002 and 2001 were impacted
by settlements with its energy provider.
Energy
Atlantic’s historical energy sales can be classified into two general
categories: Standard Offer Service (“SOS”) in CMP’s service territory
which expired February 28, 2002, and Competitive Energy Supply (“CES”) sales to
individual retail customers within the state of Maine. Effective February 27, 2004, EA no longer
serves CES or SOS retail customers and has discontinued service. Originally, EA obtained power for the sales
in CMP’s territory under an exclusive wholesale power sales agreement with
Engage Energy America, LLC.
During
the third quarter 2002, EA and Engage concluded their business relationship
pursuant to the terms of their agreement.
Following completion of the final scheduled audit, the final escrow
disbursements were made to EA and Engage on September 30, 2002. As a result of the final account settlement,
EA recognized the $4.8 million of additional standard offer service SOS revenue
during the third quarter of 2002 with an after-tax impact of $2.9 million, or
$1.84 per share.
Page 62
of 95
EA
previously entered into a contract for 40% of the output of the WS energy
facility for the two years beginning March 1, 2002 and expiring on February 29,
2004. The output from this take-or-pay contract amounted to approximately
55,000 MWH annually and was used to provide electricity for additional CES
sales within MPS’s service territory. This contract was a take-or-pay
contract, which carried more counterparty risk than others entered into by EA.
To mitigate this risk, EA entered into a contract with NB Power, whereby NB
Power committed to buy WS output in excess of load requirements in MPS’s
service territory at a rate indexed to the price of 3% Sulphur Max No. 6
residential oil into New York Harbor, which was intended to reflect NB Power’s
avoided cost, subject to a floor and ceiling. All output was sold to CES
customers, therefore limiting the risk that energy would be sold to NB
Power. In addition, NB Power committed to sell electricity to EA when
load exceeded WS output at a fixed on and off-peak rate.
In
addition, EA had a power supply relationship with Duke Energy Trading and
Marketing (“DETM”) for electricity in CMP’s service area. In connection
with this relationship, and certain transactions between EA and DETM, MPS
provided a contractual guarantee on behalf of EA in an aggregate amount of one
million dollars ($1,000,000). This guarantee was related specifically to
the delivery and/or receipt of electric power between EA and DETM. This
guarantee was renewed in September of 2002 for an additional year. Effective March 21, 2003, DETM agreed to
waive this credit requirement in lieu of EA’s commitment to maintain a $1
million ($1,000,000) minimum bank account balance. On January 27, 2004, EA notified DETM in writing of the impending
expiration of the Master Service Agreement between EA and DETM on March 1,
2004. This correspondence was to notify
DETM of EA’s expiration of its commitment to maintain a $1 million ($1,000,000)
minimum account balance as credit coverage.
The
following illustrates the types of risk EA was exposed to in connection with
the contracts for supply and sales:
• Counterparty risk, including the possibility
of the other parties’ failure to fulfill their contractual obligations to EA
such as:
a) Deliverability risk, referring to EA not being
able to serve contracted load due to the supplier’s failure to provide energy.
b) Transmission risk, indicating EA’s reliance on
utilities, such as the Company, Central Maine Power and Bangor Hydro-Electric,
to physically transport energy to EA’s customers.
c) Credit risk exposure, depending on EA’s
customers’ ability to pay, which may deteriorate during a general economic
downturn or when a commercial customer experiences financial difficulty.
• Market liquidity risk encompasses the risk of
being forced to buy or sell energy on the open market. This would have
occurred (1) if energy had not been available from WS, NB Power or other energy
supply arrangements, while the contracted customer load must still be satisfied
or (2) if the existing customer load deteriorated and NB Power could not buy
the excess power from WS, as contracted.
• Forecasting risk exposure includes possible
inaccuracy in the estimation of energy supply requirements. One of EA’s
suppliers required a 24-month forecast of load for each commitment to a 1 MW
block of energy. Although there was no penalty for not using all of the
energy, EA could have been assessed a penalty for using more than the amount
contracted.
• Market-based cost risk is exposure to
transactions tied to market indexes, such as the arrangement to sell excess WS
power to NB Power at a current market-indexed rate.
With
the expiration of the SOS arrangement in CMP’s service territory, EA has been
adversely impacted by the decrease in revenues and correspondingly,
earnings. In 2002, EA realized SOS
margin in CMP’s service territory of approximately $5.8 million, which included
the final account settlement discussed above. EA had no SOS activity in
2003. On February 24, 2003, EA
announced its intent to withdraw from the northern Maine market due to the lack
of profitability in that market, the lack of price differentiated electric
products within the Maritimes and Northern Maine Independent System Administrator
markets, and the overall illiquidity of the wholesale power market, as well as
other risk factors. EA continued to
serve its existing contracts in northern Maine through their expiration on
February 27, 2004. CES sales, primarily
in northern Maine, were approximately $6.1 million in 2003.
EA’s
decision to withdraw from the northern Maine market not only minimized its risk
profile, but EA believed this action would substantially relieve any underlying
concerns that could exist in connection with the issue of employee sharing and
EA’s energy marketing activities within MPS’s service territory. On February 21, 2003 MPS filed with the MPUC
an “Application for Exemption of Chapter 304” to exempt the Company and EA from
certain management restrictions that have arisen due to this aspect of the
corporate relationship. (MPUC Docket
No. 2003-122). In connection with its
announced intent to withdraw from the retail electricity markets in northern
Maine, EA has ceased all of its energy marketing activities in MPS’s service
territory, as well as the balance of the state, effective March 1, 2003.
Currently,
EA is an inactive subsidiary and management has ceased all active retail CES
activity on behalf of EA within the state of Maine until market conditions, the
availability of supply, the mandate for stringent credit requirements and risk
environment improve. Management will
continue to monitor both U.S. and Canadian deregulated markets to determine the
appropriate timing for possible re-entry into the deregulated retail market.
Page 63
of 95
4. SEGMENT INFORMATION
For
2003, the Company operated in three segments, with MPS providing regulated
transmission and distribution services, EA performing unregulated power
marketing services and MAM providing corporate oversight functions. The “Other” column consists primarily of
elimination activity. The table below
summarizes segment activity for 2003, 2002 and 2001.
The
Company’s reportable segments include the electric utility portion of the
business---MPS and its inactive wholly-owned Canadian subsidiary, Me&NB;
the energy marketing portion of the business---EA; and the holding company —
MAM with its other subsidiaries, MAMES and Maricor formed in late 2003. The accounting policies of the segments are
the same as those described in Note 1, “Summary of Significant Accounting
Policies.” MAM did not have any
material assets or operations until it became a holding company on June 30,
2003; however, MPS incurred expenses associated with the formation of MAM,
which totaled $639,000 in 2003, and were classified as unregulated operations
and maintenance expenses. MAM provides
certain administrative support services to MPS and EA, and MPS provides certain
support services to MAM and EA, which are billed to the respective entities at
cost, based on a combination of direct charges and allocations. The Company is organized based on products
and services.
|
|
|
(Dollars
in Thousands)
|
|
|
|
|
Twelve Months Ended December 31, 2003
|
|
|
|
|
MAM
|
|
EA
|
|
MPS
|
|
Other
|
|
Total
|
|
|
Operating Revenues
|
|
$
|
57
|
|
$
|
6,064
|
|
$
|
31,748
|
|
$
|
(8
|
)
|
$
|
37,861
|
|
|
EA Standard Offer Service Margin
|
|
—
|
|
—
|
|
—
|
|
—
|
|
0
|
|
|
Total Revenues
|
|
57
|
|
6,064
|
|
31,748
|
|
(8
|
)
|
37,861
|
|
|
Unregulated Energy Supply
|
|
—
|
|
5,229
|
|
—
|
|
(9
|
)
|
5,220
|
|
|
Operations & Maintenance (O&M)
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
|
|
—
|
|
—
|
|
12,466
|
|
(43
|
)
|
12,423
|
|
|
Unregulated
|
|
730
|
|
1,019
|
|
638
|
|
(34
|
)
|
2,353
|
|
|
Amortization – Stranded Cost
|
|
—
|
|
—
|
|
8,761
|
|
—
|
|
8,761
|
|
|
Amortization – Other
|
|
—
|
|
—
|
|
206
|
|
—
|
|
206
|
|
|
Depreciation
|
|
—
|
|
8
|
|
2,647
|
|
—
|
|
2,655
|
|
|
Other O&M
|
|
—
|
|
39
|
|
1,460
|
|
—
|
|
1,499
|
|
|
Income Taxes
|
|
(257
|
)
|
(89
|
)
|
1,930
|
|
—
|
|
1,584
|
|
|
Total Operating Expenses
|
|
473
|
|
6,206
|
|
28,108
|
|
(86
|
)
|
34,701
|
|
|
Operating Income (Loss)
|
|
(416
|
)
|
(142
|
)
|
3,640
|
|
78
|
|
3,160
|
|
|
Interest Income (Loss)
|
|
—
|
|
53
|
|
21
|
|
(26
|
)
|
48
|
|
|
Equity in Net Income of JV’s
|
|
—
|
|
—
|
|
298
|
|
(40
|
)
|
258
|
|
|
Other Income & Deductions
|
|
—
|
|
(22
|
)
|
(258
|
)
|
(78
|
)
|
(358
|
)
|
|
Income (Loss) Before Interest Charges
|
|
(416
|
)
|
(111
|
)
|
3,701
|
|
(66
|
)
|
3,108
|
|
|
Interest Charges
|
|
—
|
|
5
|
|
323
|
|
(26
|
)
|
302
|
|
|
Net Income (Loss)
|
|
$
|
(416
|
)
|
$
|
(116
|
)
|
$
|
3,378
|
|
$
|
(40
|
)
|
$
|
2,806
|
|
|
Total Assets as of December 31, 2003
|
|
$
|
3,375
|
|
$
|
2,024
|
|
$
|
135,870
|
|
|
|
$
|
141,269
|
|
Page 64
of 95
|
|
|
(Dollars
in Thousands)
|
|
|
|
|
Twelve Months Ended December 31, 2002
|
|
|
|
|
MAM
|
|
EA
|
|
MPS
|
|
Other
|
|
Total
|
|
|
Operating Revenues
|
|
$
|
—
|
|
$
|
6,901
|
|
$
|
31,410
|
|
$
|
(9
|
)
|
$
|
38,302
|
|
|
EA Standard Offer Service Margin
|
|
—
|
|
5,802
|
|
—
|
|
—
|
|
5,802
|
|
|
Total Revenues
|
|
—
|
|
12,703
|
|
31,410
|
|
(9
|
)
|
44,104
|
|
|
Unregulated Energy Supply
|
|
—
|
|
5,542
|
|
—
|
|
(9
|
)
|
5,533
|
|
|
Operations & Maintenance (O&M)
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
|
|
—
|
|
—
|
|
13,093
|
|
(48
|
)
|
13,045
|
|
|
Unregulated
|
|
—
|
|
1,444
|
|
210
|
|
—
|
|
1,654
|
|
|
Amortization – Stranded Cost
|
|
—
|
|
—
|
|
8,761
|
|
—
|
|
8,761
|
|
|
Amortization – Other
|
|
—
|
|
—
|
|
236
|
|
—
|
|
236
|
|
|
Depreciation
|
|
—
|
|
8
|
|
2,412
|
|
—
|
|
2,420
|
|
|
Other O&M
|
|
—
|
|
52
|
|
1,379
|
|
—
|
|
1,431
|
|
|
Income Taxes
|
|
—
|
|
2,251
|
|
1,908
|
|
—
|
|
4,159
|
|
|
Total Operating Expenses
|
|
—
|
|
9,297
|
|
27,999
|
|
(57
|
)
|
37,239
|
|
|
Operating Income
|
|
—
|
|
3,406
|
|
3,411
|
|
48
|
|
6,865
|
|
|
Interest Income
|
|
—
|
|
101
|
|
57
|
|
—
|
|
158
|
|
|
Equity in Net Income of JV’s
|
|
—
|
|
—
|
|
280
|
|
—
|
|
280
|
|
|
Other Income & Deductions
|
|
—
|
|
(57
|
)
|
(179
|
)
|
(48
|
)
|
(284
|
)
|
|
Income Before Interest Charges
|
|
0
|
|
3,450
|
|
3,569
|
|
0
|
|
7,019
|
|
|
Interest Charges
|
|
—
|
|
6
|
|
470
|
|
—
|
|
476
|
|
|
Net Income
|
|
$
|
0
|
|
$
|
3,444
|
|
$
|
3,099
|
|
$
|
0
|
|
$
|
6,543
|
|
|
Total Assets as of December 31, 2002
|
|
$
|
0
|
|
$
|
6,324
|
|
$
|
135,662
|
|
|
|
$
|
141,986
|
|
Page 65
of 95
|
|
|
(Dollars
in Thousands)
|
|
|
|
|
Twelve Months Ended December 31, 2001
|
|
|
|
|
MAM
|
|
EA
|
|
MPS
|
|
Other
|
|
Total
|
|
|
Operating Revenues
|
|
$
|
—
|
|
$
|
15,771
|
|
31,783
|
|
(3
|
)
|
47,551
|
|
|
EA Standard Offer Service Margin
|
|
—
|
|
2,147
|
|
—
|
|
—
|
|
2,147
|
|
|
Total Revenues
|
|
—
|
|
17,918
|
|
31,783
|
|
(3
|
)
|
49,698
|
|
|
Unregulated Energy Supply
|
|
—
|
|
14,987
|
|
—
|
|
(3
|
)
|
14,984
|
|
|
Operations & Maintenance (O&M)
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
|
|
—
|
|
—
|
|
10,541
|
|
(130
|
)
|
10,411
|
|
|
Unregulated
|
|
—
|
|
1,226
|
|
—
|
|
—
|
|
1,226
|
|
|
Amortization – Stranded Cost
|
|
—
|
|
—
|
|
9,260
|
|
—
|
|
9,260
|
|
|
Amortization – Other
|
|
—
|
|
—
|
|
217
|
|
—
|
|
217
|
|
|
Depreciation
|
|
—
|
|
6
|
|
2,496
|
|
—
|
|
2,502
|
|
|
Other O&M
|
|
—
|
|
59
|
|
1,285
|
|
—
|
|
1,344
|
|
|
Income Taxes
|
|
—
|
|
650
|
|
2,743
|
|
—
|
|
3,393
|
|
|
Total Operating Expenses
|
|
—
|
|
16,928
|
|
26,542
|
|
(133
|
)
|
43,337
|
|
|
Operating Income
|
|
—
|
|
990
|
|
5,241
|
|
130
|
|
6,361
|
|
|
Interest Income (Loss)
|
|
—
|
|
(103
|
)
|
271
|
|
—
|
|
168
|
|
|
Equity in Net Income of JV’s
|
|
—
|
|
—
|
|
299
|
|
—
|
|
299
|
|
|
Other Income & Deductions
|
|
—
|
|
16
|
|
(186
|
)
|
(130
|
)
|
(300
|
)
|
|
Income Before Interest Charges
|
|
0
|
|
903
|
|
5,625
|
|
0
|
|
6,528
|
|
|
Interest Charges
|
|
—
|
|
6
|
|
1,285
|
|
—
|
|
1,291
|
|
|
Net Income
|
|
$
|
0
|
|
$
|
897
|
|
$
|
4,340
|
|
$
|
0
|
|
$
|
5,237
|
|
|
Total Assets as of December 31, 2001
|
|
$
|
0
|
|
$
|
5,632
|
|
$
|
137,703
|
|
|
|
$
|
143,335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
2003 and 2002, total assets reflect the reclassification of accrued removal
obligations as a liability from accumulated depreciation.
Page 66
of 95
5. INVESTMENTS IN ASSOCIATED COMPANIES
MPS
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 MEPCO, a jointly-owned electric transmission company. MPS records its investment in MEPCO and
Maine Yankee using the equity method.
For additional information, see Note 12, “Commitments, Contingencies and
Regulatory Matters — Capacity Arrangements – Maine Yankee” regarding the
closing and decommissioning of Maine Yankee.
Dividends
received during 2003, 2002, and 2001 from Maine Yankee were $301,050, $99,828
and $206,000, respectively, and from MEPCO $99,205, $7,249 and $7,249,
respectively. In 2003, 2002 and 2001,
MPS also received Maine Yankee stock redemptions of $524,724, $375,277 and
$499,484 respectively. Substantially
all earnings of Maine Yankee and MEPCO are distributed to investor
companies. Condensed financial
information (unaudited) for Maine Yankee and MEPCO is as follows:
|
|
|
Maine Yankee
|
|
MEPCO
|
|
|
(Dollars
in Thousands)
|
|
2003
|
|
2002
|
|
2001
|
|
2003
|
|
2002
|
|
2001
|
|
|
Earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
53,222
|
|
$
|
58,924
|
|
$
|
61,994
|
|
$
|
3,792
|
|
$
|
4,365
|
|
$
|
4,514
|
|
|
Earnings applicable to Common Stock
|
|
$
|
3,217
|
|
$
|
3,947
|
|
$
|
4,371
|
|
$
|
1,258
|
|
$
|
1,068
|
|
$
|
1,152
|
|
|
Company’s equity share of net earnings
|
|
$
|
161
|
|
$
|
197
|
|
$
|
219
|
|
$
|
94
|
|
$
|
80
|
|
$
|
86
|
|
|
Investment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
561,523
|
|
$
|
679,975
|
|
$
|
802,118
|
|
$
|
8,100
|
|
$
|
8,260
|
|
$
|
7,396
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
2,680
|
|
21,600
|
|
31,200
|
|
—
|
|
—
|
|
—
|
|
|
Other liabilities and deferred credits
|
|
514,423
|
|
600,656
|
|
707,643
|
|
1,142
|
|
1,214
|
|
1,320
|
|
|
Net assets
|
|
$
|
44,420
|
|
$
|
57,719
|
|
$
|
63,275
|
|
$
|
6,958
|
|
$
|
7,046
|
|
$
|
6,076
|
|
|
MPS’s equity in net assets
|
|
$
|
2,221
|
|
$
|
2,886
|
|
$
|
3,164
|
|
$
|
521
|
|
$
|
528
|
|
$
|
455
|
|
In
accordance with a plan approved by the Securities and Exchange Commission,
Maine Yankee has started the redemption of its common stock periodically
through 2008.
|
Maine Yankee
Board Meeting
|
|
Total Shares
Redeemed
|
|
MPS
Shares
|
|
Amounts
Received
|
|
Date
Received
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 27, 2001
|
|
75,200
|
|
3,760
|
|
$
|
499,484
|
|
October 4, 2001
|
|
|
June 27, 2002
|
|
22,600
|
|
1,130
|
|
150,110
|
|
July 11, 2002
|
|
|
September 26, 2002
|
|
33,900
|
|
1,695
|
|
225,166
|
|
October 4, 2002
|
|
|
December 18, 2002
|
|
33,800
|
|
1,690
|
|
224,502
|
|
January 9, 2003
|
|
|
September 25, 2003
|
|
45,200
|
|
2,260
|
|
300,222
|
|
October 14, 2003
|
|
|
December 17, 2003
|
|
30,100
|
|
1,505
|
|
199,926
|
|
January 7, 2004
|
|
|
|
|
240,800
|
|
12,040
|
|
$
|
1,599,410
|
|
|
|
6. SHORT-TERM CREDIT ARRANGEMENTS
MPS
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 June 8, 2004. MPS
is currently seeking an extension of this facility and management believes
these efforts will be successful. These
agreements contain certain restrictive covenants including interest coverage
tests and debt-to-equity ratios. As of
December 31, 2003, MPS was in compliance with those covenants. MPS 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 MPS and each of the participating banks. The A Loans, at MPS’s option, bear interest equal to either the
agent bank’s prime rate or LIBOR-based pricing. MPS also pays a quarterly commitment fee of .50% of the unused
portion of the A Loans. The B Loans
bear interest as arranged between MPS and the participating bank. As of December 31, 2003, A Loans for $5.0
million were outstanding under the revolving credit arrangement at an interest
rate of 2.5625%, as well as a B Loan of $200,000 of 2.76%. An A Loan for $2.0 million and a B Loan for
$800,000 were outstanding as of December 31, 2002 under the revolving credit
arrangement at interest rates of 2.875% and 3.02%, respectively.
On
October 1, 2003, MPS executed an additional $3 million line of credit with the
Bank of New York. This new facility is
unsecured and will expire on March 29, 2004.
MPS is currently seeking an extension of this facility and management
believes these efforts will be successful.
Interest rates on the new facility are comparable to the rates on the
existing revolving credit agreement.
The additional facility provides an additional source of short-term
borrowings in the event required borrowings exceed the existing revolving
credit agreement. As of December 31,
2003, $1 million was outstanding on the facility at 2.8125%.
Page 67
of 95
EA
has a revolving line of credit with a bank, for $1.2 million. In May of 2003, the line was extended until
March 29, 2004. Interest is based on
the bank’s prime lending rate. As of
December 31, 2003, EA was in compliance with the covenants set forth by the
line of credit agreement. The line was
not used during 2003 and 2002 and had no balance outstanding as of December 31,
2003 or December 31, 2002.
7. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
MPS
has three issues of long-term debt with variable interest rates. Pursuant to its rate order in MPUC Docket
2003-85, as more fully explained in Note 12, “Commitments, Contingencies and
Regulatory Matters, MPUC Approves Rate Increase,” MPS agreed to fix its
interest rates and the MPUC allowed recovery of the fixed interest costs in
rates. On September 9, 2003, MPS executed
swap agreements for the three variable rate issues, locking in the rates over
the remaining terms of the issues. For
the Finance Authority of Maine (“FAME”) 1998 Taxable Elective Rate
Stabilization Revenue Notes due 2008, the effective fixed interest rate has
been set at 2.79%. For the two series
of tax-exempt bonds issued by the Maine Public Utilities Financing Bank
(“MPUFB”), the effective fixed interest rates for the 1996 Series due 2021 and
the 2000 Series due 2025 are 4.57% and 4.68% respectively.
At
the end of 2003, the fair value of these qualified cash flow hedges was
($1,185,000), reflecting a drop in swap rates since the execution date. Since September 9, 2003, the difference
between the fixed rates and the underlying variable rates on the issues of
approximately $294,000 was charged to operating income in 2003. The fixed rates are higher than the previous floating rates and
continue to be as of the date of this filing. Although the fixed interest rates were higher than the underlying
variable rates, a portion of a MPUC approved rate increase effective November
1, 2003, was to cover this difference.
Management believes that the fixing of interest rates over the terms of
MPS’s debt will serve to protect both shareholders and consumers from what it
believes to be inevitable rising interest rates. The loss in fair value on the interest rate swaps noted above
less the deferred tax of $473,000 has been recorded as Other Comprehensive
Income (Loss), in accordance with SFAS 133, “Accounting for Derivative
Instruments and Hedging Activities.”
Gains or losses in the fair market value of the interest rate swaps do
not impact net income or the revenues of MPS, unless shareholder’s common
equity falls below the minimum allowable 48 percent as set by the MPUC.
On
November 20, 2000, MPS purchased an interest cap of 6% that applied to the 2000
and 1996 Series of Maine Public Utilities Financing Bank’s (“MPUFB”) bonds
issued on behalf of MPS with outstanding balances of $9 million and $13.6
million, respectively. The interest cap
expired in November, 2003.
On
June 1, 1998, MPS purchased an interest rate cap of 7% at a cost of $172,000,
to expire June 8, 2008 on $11,540,000 of FAME’s Taxable Electric Rate
Stabilization Notes, Series 1998A, issued on behalf of MPS. In accordance with the rate treatment
prescribed by the MPUC, the original cost of the interest rate cap has been
amortized along with other issuance costs with $96,000 and $79,000 remaining at
the end of 2003 and 2002, respectively, as a regulatory asset. The provider of the cap estimated its value
at the end of 2003 as approximately $27,000.
8. LONG-TERM DEBT
On
October 19, 2000, the Maine Public Utilities Financing Bank (“MPUFB”) issued $9
million of its tax-exempt bonds due October 1, 2025 (“2000 Series”) on behalf
of MPS. The proceeds were placed in
trust to be drawn down for the reimbursement of issuance costs and for the
construction of qualifying distribution property. As of December 31, 2002, the proceeds in the trust account were
$2.1 million. On October 17, 2003, MPS received the final distribution from the
trust. Pursuant to the long-term note
issued under a loan agreement between MPS and the MPUFB, MPS has agreed to make
payments to the MPUFB for the principal and interest on the bonds. Concurrently, pursuant to a letter of credit
and reimbursement agreement, MPS caused a Direct Pay Letter of Credit for an
initial term of nineteen months, subsequently extended until June, 2004, to be
issued by The Bank of New York for the benefit of the holders of such bonds. MPS is currently seeking an extension of
the Direct Pay Letter of Credit and management believes these efforts will be
successful. To secure MPS’s obligations
under the letter of credit and reimbursement agreement, MPS issued first and
second mortgage bonds, in the amounts of $5.0 million and $4.525 million,
respectively. MPS has the option of
selecting weekly, monthly, annual or term interest rate periods for the 2000
Series, and, at issuance, selected the weekly interest period, with an initial
interest rate of 4.35%. On November 20,
2000, MPS purchased an interest rate cap of 6% at a cost of $36,000 that
expired in November 2003, that applied to the 2000 and 1996 Series, as
described below. At the end of 2003,
the cumulative effective interest rate of the 2000 Series, including the
effective fixed swap rate of 4.68%, issuance costs and credit enhancement fees
since issuance was 7.14%.
A
similarly structured series of Bonds was issued on behalf of MPS by the MPUFB
in 1996 (“1996 Series”), with $13.6 million outstanding due in 2021. A Direct Pay Letter of Credit was issued by
The Bank of New York, which has been extended to June 2004, and is secured by
$14.4 million of second mortgage bonds.
At the end of 2003, the cumulative effective interest rate of the 1996
series, including the effective fixed swap rate of 4.57%, issuance costs and
credit enhancement fees was 6.13%.
On May 29, 1998, FAME issued $11,540,000 of its Taxable Electric Rate
Stabilization Revenue Notes, Series 1998A (MPS) (“Notes”) on behalf of
MPS. 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
Page 68
of 95
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 MPS and the Capital Reserve Fund held by the
Trustee, which was approximately $2.4 million at the end of 2003 and 2002. MPS has issued $4.0 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 and will be adjusted
weekly. On June 1, 1998, MPS 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 2003, the cumulative effective
interest rate, including the fixed swap rate of 2.79%, issuance costs and
credit enhancement fees for the Notes was 3.81%.
The
MPUFB tax-exempt issues are subject to the same restrictive covenants as those
discussed for MPS’s revolving credit arrangement in Note 6, “Short-Term Credit
Arrangements.”
9. STOCK COMPENSATION PLAN
Upon
approval by MPS’s shareholders in June of 2002, MPS adopted the 2002 Stock
Option Plan (the “Plan”). The Plan was
subsequently adopted by the Company after its formation. The Plan provides designated employees of
the Company and its Subsidiaries with stock ownership opportunities and
additional incentives to contribute to the success of the Company, and to
attract, reward and retain employees of outstanding ability. The Plan is administered by the members of
the Performance and Compensation Committee of the Board of Directors, who are
not employees of the Company or its Subsidiaries. The Company may grant options to its employees for up to 150,000
shares of common stock, provided that the maximum aggregate number of shares
which may be issued under the plan pursuant to incentive stock options shall be
120,000 shares. The exercise price for
shares to be issued under any incentive stock option shall not be less than one
hundred percent (100%) of the fair market value of such shares on the date the
option is granted. An option’s maximum
term is 10 years. Prior to the issuance
of options to the Company’s President and Chief Executive Officer, the Board,
based on a recommendation of the Performance and Compensation Committee,
modified the grant agreement to lessen the economic liability to the
Company. As modified, the change of
control provisions were eliminated and the three-year vesting schedule will be
followed.
The
Company accounts for the fair value of its grants under the plan in accordance
with the expense provisions of Statement of Financial Accounting Standards No.
123, “Accounting for Stock-Based Compensation.” The effect of the grants on compensation expense for the year
ended December 31, 2003 was immaterial.
The
fair value of each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted-average
assumptions used for grants: dividend yield of 4.34 percent; expected
volatility of 20 percent, risk-free interest rate of 3.64%; and expected lives
of 7 years.
A
summary of the status of the Company’s stock option plan as of December 31,
2003, and changes during the year then ended is presented below:
|
Options
|
|
Shares
|
|
Exercise
Price
|
|
|
Outstanding at January 1, 2003
|
|
5,250
|
|
$
|
30.45
|
|
|
Granted
|
|
5,250
|
|
$
|
32.51
|
|
|
Exercised
|
|
—
|
|
—
|
|
|
Forfeited
|
|
—
|
|
—
|
|
|
Outstanding at December 31, 2003
|
|
10,500
|
|
$
|
31.48
|
|
|
Options exercisable at December 31, 2003
|
|
0
|
|
|
|
|
Weighted-average fair value of options
granted
|
|
$
|
6.03
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes information about fixed stock options
outstanding at December 31, 2003:
|
Options
Outstanding
|
|
Options
Exercisable
|
|
|
Range of Exercise
Prices
|
|
Number
Outstanding at
12/31/03
|
|
Weighted-
Average
Remaining
Contractual Life
|
|
Weighted-
Average
Exercise
Price
|
|
Number
Exercisable
at 12/31/03
|
|
Weighted-
Average Exercise
Price
|
|
|
$30.45 - $32.51
|
|
10,500
|
|
9.0 years
|
|
31.48
|
|
—
|
|
—
|
|
Page 69
of 95
10. 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. The Company made tax-deductible
contributions of $409,000 for the 2003 plan year in December, 2003 and $276,570
for the 2002 plan year in January, 2003.
Health Care Benefits
In
addition to providing pension benefits, the Company provides certain health
care benefits to eligible employees and retirees. All employees and retirees share in the cost of their medical
benefits, in addition to plan deductibles and coinsurance payments, totaling
approximately 12.2% and 11.26% of medical insurance premiums in 2003 and 2002,
respectively. In 2002, certain
amendments were made to the plan, including the following. Effective with retirements after January 1,
1995 and employees hired before January 1, 2003, retirees will be eligible for
retiree medical coverage after completing twenty years of service, subject to a
contribution schedule. Employees hired
after January 1, 2003 will be eligible for retiree medical coverage after
completing twenty-five years of service; however, their spouse will not be
eligible for coverage. For employees
hired after December 31, 1999 and prior to January 1, 2003, spousal retiree
medical coverage ceases upon the spouse’s attainment of age 65. Retirees who were hired before January 1,
2003 will contribute to the cost of their coverage starting at 60% for retirees
with twenty years of service with the contribution declining to $69.33 per
month until age 65 and $21.62 per month thereafter for thirty or more years of
service. Retirees who were hired after
January 1, 2003 will contribute to the cost of their coverage starting at 70%
for retirees with twenty-five years of service and declining to the
above-mentioned monthly amounts for thirty or more years of service. The above amendments in plan provisions have
been incorporated into the calculation of the related actuarial benefit
obligation.
Based
on prior MPUC accounting orders, the Company established a regulatory asset of
approximately $1,061,000, representing deferred post-retirement benefits. As an element of its four-year rate plan,
the Company began recovering these deferred expenses over a ten-year period,
along with the annual expenses in excess of pay-as-you-go expenses, starting in
1996. The Company made a payment of
$354,000 to fund the 401(h) sub-account of the Pension Trust for non-union
retiree medical payments on September 14, 2000 and $92,190 on June 19,
2003. On December 28, 1999
and December 27, 2001, the Company made payments of $2.1 million and $641,000,
respectively, to a Voluntary Employee Benefit Association (“VEBA”) trust fund,
an independent external trust fund for union retiree medical payments. These payments provide funding for future
post-retirement health care costs at such time as customers are paying for
these costs in their rates. For
purposes of determining the accrued post-retirement benefit cost as of December
31, 2003 the health care cost trend rate used was 8% in 2004 and graded down to
4% in 2013, 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:
|
|
|
One-Percentage-Point
|
|
|
(Dollars
in Thousands)
|
|
Increase
|
|
Decrease
|
|
|
|
|
|
|
|
|
|
Effect on total cost of service and
interest cost components
|
|
$
|
135
|
|
$
|
(107
|
)
|
|
|
|
|
|
|
|
|
Effect on post-retirement benefit
obligation
|
|
$
|
1,408
|
|
$
|
(1,146
|
)
|
Page 70
of 95
The
following table sets forth the plans’ change in benefit obligation, change in
plan assets, funded status and assumptions as of December 31, 2003 and 2002:
|
|
|
Pension
Benefits
|
|
Health
Care
Benefits
|
|
|
(Dollars in Thousands)
|
|
2003
|
|
2002
|
|
2003
|
|
2002
|
|
|
Changes in benefit
obligation
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
17,839
|
|
$
|
16,604
|
|
$
|
8,924
|
|
$
|
7,930
|
|
|
Service cost
|
|
430
|
|
411
|
|
193
|
|
175
|
|
|
Interest cost
|
|
1,144
|
|
1,132
|
|
539
|
|
577
|
|
|
Amendments
|
|
—
|
|
—
|
|
—
|
|
(699
|
)
|
|
Termination benefits
|
|
—
|
|
231
|
|
—
|
|
171
|
|
|
Actuarial loss
|
|
992
|
|
640
|
|
488
|
|
1,233
|
|
|
Employee’s contributions
|
|
—
|
|
—
|
|
31
|
|
1
|
|
|
Benefits paid
|
|
(1,219
|
)
|
(1,051
|
)
|
(549
|
)
|
(460
|
)
|
|
Administrative expenses
|
|
(114
|
)
|
(128
|
)
|
—
|
|
(3
|
)
|
|
Benefit obligation at End of year
|
|
19,072
|
|
17,839
|
|
9,626
|
|
8,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan
assets
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at Beginning of
year
|
|
13,330
|
|
14,731
|
|
2,336
|
|
2,644
|
|
|
Actual return on plan assets
|
|
2,213
|
|
(222
|
)
|
393
|
|
(143
|
)
|
|
Employee contributions
|
|
—
|
|
—
|
|
31
|
|
1
|
|
|
Employer contribution
|
|
686
|
|
—
|
|
423
|
|
298
|
|
|
Benefits paid
|
|
(1,219
|
)
|
(1,051
|
)
|
(549
|
)
|
(460
|
)
|
|
Administrative expenses
|
|
(114
|
)
|
(128
|
)
|
—
|
|
(3
|
)
|
|
Fair value of plan assets at end of year
|
|
14,896
|
|
13,330
|
|
2,634
|
|
2,337
|
|
|
Funded Status
(Benefit Obligation - Fair Value at end of year)
|
|
(4,176
|
)
|
(4,509
|
)
|
(6,992
|
)
|
(6,588
|
)
|
|
Unrecognized transition (asset) obligation
|
|
—
|
|
(16
|
)
|
1,272
|
|
1,415
|
|
|
Unrecognized prior service costs
|
|
569
|
|
658
|
|
(467
|
)
|
(527
|
)
|
|
Unrecognized net actuarial (gain)/loss
|
|
1,651
|
|
1,634
|
|
4,807
|
|
4,708
|
|
|
Accrued benefit
cost
|
|
$
|
(1,956
|
)
|
$
|
(2,233
|
)
|
$
|
(1,380
|
)
|
$
|
(992
|
)
|
|
Weighted-average assumptions as of December
31 (measurement date)
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
6.25
|
%
|
6.50
|
%
|
6.25
|
%
|
6.50
|
%
|
|
Expected return on plan assets
|
|
8.50
|
%
|
8.50
|
%
|
8.50
|
%
|
8.50
|
%
|
|
Rate of compensation increase
|
|
4.00
|
%
|
4.00
|
%
|
N/A
|
|
N/A
|
|
The
Company uses a December 31 measurement date for its pension and post-retirement
benefit plans. The Company’s
accumulated benefit obligation for all defined benefit pensions plans was $16.2
million and $15.4 million at December 31, 2003 and 2002, respectively.
|
|
|
|
|
Percentage
of Plan Assets at
December 31
|
|
|
|
|
Target
Allocation
|
|
|
|
|
|
2004
|
|
2003
|
|
2002
|
|
|
Plan Assets
|
|
|
|
|
|
|
|
|
Pension Plan
|
|
|
|
|
|
|
|
|
Asset Category
|
|
|
|
|
|
|
|
|
Equity Securities
|
|
50-60
|
%
|
52
|
%
|
46
|
%
|
|
Debt Securities
|
|
40-50
|
%
|
36
|
%
|
44
|
%
|
|
Real Estate
|
|
0
|
%
|
0
|
%
|
0
|
%
|
|
Other
|
|
5-15
|
%
|
12
|
%
|
10
|
%
|
|
Total
|
|
|
|
100
|
%
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
Health Care
Benefits
|
|
|
|
|
|
|
|
|
Asset Category
|
|
|
|
|
|
|
|
|
Equity Securities
|
|
52-63
|
%
|
61
|
%
|
53
|
%
|
|
Debt Securities
|
|
37-48
|
%
|
39
|
%
|
47
|
%
|
|
Real Estate
|
|
0
|
%
|
0
|
%
|
0
|
%
|
|
Other
|
|
0-5
|
%
|
0
|
%
|
0
|
%
|
|
Total
|
|
|
|
100
|
%
|
100
|
%
|
Page 71
of 95
The
investment objective is to achieve long-term growth of capital, with exposure
to risk set at an appropriate level.
This objective shall be accomplished through the utilization of a
diversified asset mix consisting of equities (domestic and international) and
taxable fixed income securities. The
account is to be managed on a fully discretionary basis to obtain the highest
total rate of return in keeping with a moderate level of risk. The target rate of return for the portfolio
will be 8.5% with the goal of exceeding returns of the S&P 500 on the
equity side and the Lehman Brothers Aggregate Bond Index on the fixed income
side.
The
following table sets forth the plans’ net periodic benefit cost for 2003, 2002
and 2001:
|
|
|
Pension
Benefits
|
|
Health
Care Benefits
|
|
|
(Dollars
in Thousands)
|
|
2003
|
|
2002
|
|
2001
|
|
2003
|
|
2002
|
|
2001
|
|
|
Service cost
|
|
$
|
430
|
|
$
|
411
|
|
$
|
342
|
|
$
|
193
|
|
$
|
175
|
|
$
|
108
|
|
|
Interest cost
|
|
1,144
|
|
1,132
|
|
1,105
|
|
539
|
|
577
|
|
431
|
|
|
Expected return on plan assets
|
|
(1,239
|
)
|
(1,279
|
)
|
(1,277
|
)
|
(195
|
)
|
(218
|
)
|
(192
|
)
|
|
Amortization of transition obligation
|
|
(16
|
)
|
(77
|
)
|
(77
|
)
|
142
|
|
213
|
|
213
|
|
|
Amortization of prior service cost
|
|
90
|
|
90
|
|
90
|
|
(60
|
)
|
(60
|
)
|
(60
|
)
|
|
Recognized net actuarial (gain)
|
|
—
|
|
—
|
|
(65
|
)
|
192
|
|
176
|
|
29
|
|
|
Net periodic benefit cost
|
|
$
|
409
|
|
$
|
277
|
|
$
|
118
|
|
$
|
811
|
|
$
|
863
|
|
$
|
529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional FAS 88 Termination Benefit
|
|
—
|
|
$
|
231
|
|
—
|
|
—
|
|
$
|
171
|
|
—
|
|
In
November, 2002, a Voluntary Early Retirement Program (VERP) was offered to
employees age 59 and over with 16 years of service. Of the 13 employees eligible for the program, 10 accepted the
program and retired effective January 1, 2003.
The impact of the VERP is included in “Additional FAS 88 Termination
Benefit,” above.
|
|
|
Pension
Benefits
|
|
Health
Care Benefits
|
|
|
Cash Flows
|
|
Employer
|
|
Employee
|
|
Participants
|
|
|
Contributions
|
|
|
|
|
|
|
|
|
2002
|
|
$
|
0
|
|
$
|
297,797
|
|
$
|
1,032
|
|
|
2003
|
|
$
|
685,570
|
|
$
|
422,804
|
|
$
|
30,707
|
|
|
Expected 2004
|
|
$
|
400,000
|
|
$
|
505,869
|
|
$
|
30,665
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Payments
|
|
|
|
|
|
|
|
|
2002
|
|
$
|
1,051,107
|
|
$
|
460,391
|
|
|
|
|
2003
|
|
$
|
1,219,266
|
|
$
|
549,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Future Benefit Payments
|
|
|
|
|
|
|
|
|
2004
|
|
$
|
1,106,582
|
|
$
|
582,180
|
|
|
|
|
2005
|
|
$
|
1,089,107
|
|
$
|
580,407
|
|
|
|
|
2006
|
|
$
|
1,072,849
|
|
$
|
591,450
|
|
|
|
|
2007
|
|
$
|
1,062,763
|
|
$
|
600,287
|
|
|
|
|
2008
|
|
$
|
1,055,360
|
|
$
|
615,462
|
|
|
|
|
Years 2009 – 2013
|
|
$
|
5,738,340
|
|
$
|
3,625,219
|
|
|
|
On
December 8, 2003, President Bush signed into law the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (“the Act”). The Act introduces
a federal subsidy to sponsors of retiree health care benefit plans that provide
a benefit that is at least actuarially equivalent to Medicare Part D.
In
accordance with FASB Staff Position No. FAS 106-1, any measures of the
accumulated pension benefit obligation (“APBO”) or net periodic post-retirement
benefit cost in the Company’s financial statements or accompanying notes do not
reflect the effects of the Act on its plan.
Specific authoritative guidance on the accounting for the federal
subsidy is pending and that guidance, when issued, could require a sponsor to
change previously reported information. Moreover, the issues of how and when
the federal subsidy should be accounted for are not yet resolved by the FASB.
The Company has not yet determined the potential effects of the Act on its
future post-retirement costs, including the participation rates in its benefit
plans, nor whether any amendments to its benefit plans are appropriate given
the provisions of the Act.
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 2% 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 $112,000, $117,000 and $114,000 in 2003, 2002, and
2001, respectively.
Page 72
of 95
11. 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, 2003, the Company’s long term debt had a carrying value
and a fair value of approximately $30.7 million.
12. COMMITMENTS, CONTINGENCIES AND REGULATORY MATTERS
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, MPS filed its determination of stranded costs,
transmission and distribution costs, and rate design with the MPUC. MPS’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 occurred 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 WS, the obligation
for remaining operating expenses and recovery of MPS’s remaining investment in
Maine Yankee, and the recovery of several other regulatory assets.
On
October 15, 1999, MPS filed with the MPUC a Stipulation resolving the revenue
requirement and rate design issues for MPS’s transmission and distribution
(“T&D”) utility. This Stipulation
was signed by the Office of Public Advocate and approval was recommended by the
MPUC Staff. Under the Stipulation,
MPS’s total annual T&D revenue requirement of $16,640,000, went into effect
on 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
MPS’s generating assets, but did set forth some general principles concerning
MPS’s ultimate stranded costs recovery, including agreement that the major
components of MPS’s stranded costs are legitimate, verifiable and unmitigable,
and therefore subject to recovery in rates.
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 MPS’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, with that level of recovery set for two
years. This revenue requirement
includes a return on un-recovered stranded investment based on the capital
structure approved by the MPUC in its December 1, 1999 Order. The approved capital structure consists of
51% common equity with an authorized return on equity of 10.7%. The Phase II Stipulation also allowed MPS to
offset its un-recovered stranded investment in Seabrook by approximately $7
million, (details provided in chart in “Capacity
Arrangements — Generating Asset Sale,” below) 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, MPS was granted several
accounting orders incorporating certain accounting methodologies used in
determining the elements of stranded costs.
On August 4, 2000, the MPUC authorized MPS to record the difference
between the approved contracts for two large industrial customers and their
current special discount rates, designed for customer retention, as revenue and
a regulatory asset. This flexible
pricing adjustment resulted in recognition of $200,000 and $961,000 of revenues
and a corresponding regulatory asset in 2002 and 2001, respectively. The annual revenue requirement associated
with the recovery of stranded costs will be reviewed at least every three
years, and was reviewed in late 2001 and late 2003. See “MPUC Approves Stranded Cost Revenue Requirements Effective
March 1, 2002,” and “MPUC Approves Stranded Cost Revenue Requirements Effective
March 1, 2004” below, for additional information.
MPUC Approves Stranded Cost Revenue Requirements Effective
March 1, 2002
On
May 8, 2001, the MPUC issued a notice of investigation to determine whether
MPS’s annual recovery of $12.5 million in stranded investment must be changed,
effective March 1, 2002, to reflect any changes in its stranded costs. On July 12, 2001, MPS filed its proposal in
which it advocated continuing the $12.5 million annual recovery of stranded
costs and also proposed to begin the recovery of deferred amounts associated
with the discounted rates it had made available to certain industrial
customers. Also at issue in the
proceeding was an insurance refund associated with Maine Yankee, of which MPS’s
share is $1,005,000. As of December 31,
2001, MPS reflected the refund as a miscellaneous deferred credit. In February, 2002, $854,000 of the refund
was applied to stranded costs and $151,000 of the refund was applied to other
non-operating revenue. A Stipulation
placed before the MPUC in January, 2002 included annual stranded cost recovery
of $11,540,000 and a 15% sharing of the Maine Yankee insurance refund with
MPS’s shareholders, thereby leaving the rates charged to retail customers the
same. This Stipulation was approved by
the MPUC on January 7, 2002, and the appropriate order was issued on February
27, 2002.
MPUC Approves Stranded Cost Revenue Requirements Effective
March 1, 2004
In
an Order dated February 27, 2004, MPS received final approval from the MPUC for
the stranded cost revenue component of its electric delivery rates, effective
March 1, 2004. Under Title 35-A of the Maine Revised Statutes Annotated,
Section 3208, the MPUC is required to periodically investigate and adjust the
stranded cost charges reflected in the rates of a transmission and distribution
utility. In accordance with this provision, on September 16, 2003, in
Docket No. 2003-666, the MPUC issued a notice of investigation in order to
determine whether MPS’s rates must be changed effective March 1, 2004 to
reflect any changes in MPS’s stranded costs. On February 27, 2004, the MPUC
issued an order approving a stipulation under which MPS is allowed to recover
$11,785,339 per year to satisfy its approved stranded cost revenue requirements
for the “rate effective period” beginning March 1, 2004 and ending on December
31, 2006. The approved revenue
requirement for the rate effective period ended February 29, 2004 was
$11,540,000. Under the approved
stipulation MPS’s stranded
Page 73
of 95
cost
rates approved in Docket No. 2003-85 will remain in effect during the rate
effective period. The stipulation approved by the MPUC in
Docket 2003-666 also approved and reaffirmed each of the elements and
associated balances of MPS’s recoverable stranded costs.
As
explained more fully below, during the course of Docket 2003-666 the parties
reviewed the manner in which MPS was recovering and accounting for its carrying
charges associated with the deferred fuel element of its stranded cost. As a result of the stipulation approved in
Docket No. 2003-666, MPS will record deferred income tax expense associated
with deferred fuel carrying charges during the rate effective period from March
1, 2004 through December 31, 2006, as compared to past treatment where such
expense was deferred for future recovery.
Because the deferred fuel carrying charge component of MPS’s stranded
costs is not expected to fully amortize until 2012, the Company anticipates
that deferred income tax expense will be incurred through 2012, subject to
future stranded cost filings with the MPUC.
In Dockets 98-577 and 2001-240, the parties stipulated that MPS would
accrue carrying costs on its unrecovered fuel balance (the “deferred fuel
account”) during the respective rate effective period at its net of tax cost of
capital rate. Consistent with the stipulation in Docket No. 2001-240, MPS
accrued a carrying charge using the net of tax rate of 7.98% through October
31, 2003 applied against its unrecovered deferred fuel balance. From
November 1, 2003 to December 31, 2003 MPS accrued its carrying charge using a
net of tax rate of 7.06%, based on the cost of capital approved in Docket No.
2003-85 (described in Docket 2003-85 Partial Stipulation filed on September 2,
2003).
During
the course of the Docket 2003-666 proceeding, MPS determined that it had not
previously recognized accumulated deferred income taxes with respect to the
carrying charges on the deferred fuel account and that the recording of a
deferred tax liability to its balance sheet pursuant to FAS 109 in the amount
of $2.896 million was required, of this, $2.739 million was recorded as of
December 31, 2003. The deferred fuel balance as of March 1, 2004 prior to any
adjustment is projected to be $18,838,000.
Under the stipulation MPS is allowed to adjust its accumulated deferred income
tax account and the deferred fuel balance by $2,896,000, as of March 1, 2004,
resulting in a total projected deferred balance as of March 1, 2004 of
$21,734,000. Under the approved stipulation the parties also agreed that
the return component on the deferred fuel balance should be reduced in such a
manner that ratepayers were held harmless on a net present value basis as a
result of the March 1, 2004 adjustment to the deferred fuel balance.
During the rate effective period ending on December 31, 2006, the overall
pre-tax return component on the deferred fuel balance will be 8.28%, reflecting
a 6.17% return on equity. The return on the deferred fuel balance will be
reviewed in future stranded cost rate setting proceedings and will be adjusted
as necessary in order that the present value of the revenue requirements of the
deferred fuel account without the adjustments described above equals the
present value of the revenue requirements of the deferred fuel account with the
adjustments. MPS concludes that as a result of this stipulation and the
foregoing described adjustment to the deferred fuel balance and the accumulated
deferred income tax liability that no further adjustment is necessary under FAS
109 in order to reflect prior unrecorded deferred income taxes.
The
decreased cost of capital rate beginning on March 1, 2004 will have an impact
on future stranded cost earnings and cash flow, but will not impact future
distribution or transmission earnings. In the year 2004, the Company
anticipates that it will record deferred income tax expense of approximately
$412,000 associated with the deferred fuel carrying charges. The amount of deferred income tax expense
recorded in future years will vary depending upon the amount of the accrued
carrying charge in any year, and the tax rates then in effect. The Company anticipates that earnings from
carrying charges on its stranded costs in 2004 will be approximately $267,000
lower than the amount that would have been recorded had the Company continued
to use the original cost of capital on its deferred fuel balance, for a total
earnings impact of $679,000 in 2004.
The impact on future earnings resulting from the agreed upon lower cost
of capital, when compared against the cost of capital used in prior stranded
cost filings, will vary. Schedules filed by
the Company as part of the
stipulation in Docket No. 2003-666 reflect the deferred fuel balance as of
March 1, 2003, certain additions to relating to the Wheelabrator-Sherman
above-market contract through December, 2006 and the amortization of the
deferred fuel balance though 2012.
Applying these assumptions, current tax rates and the agreed upon cost
of capital, the Company anticipates that the impact on future earnings
resulting from recording deferred income taxes on accrued carrying charges and
applying a lower cost of capital to the deferred fuel balance could range from
$1.0 million in 2005, increasing to $1.2 million in 2007, then gradually
decreasing to $17,000 in 2012. These
amounts may vary with changes in the deferred fuel balance and other variables
which the Company cannot predict with certainty at this time. Management is analyzing means to mitigate
the impact of this stipulation on future net income and cash flows.
In
addition to the return allowed on its deferred fuel account as set forth above,
under the approved stipulation MPS shall be allowed to recover the following
pre-tax returns on the applicable stranded cost rate base components during the
rate effective period: (i) the pre-tax return on unrecovered balance of the
Wheelabrator-Sherman Contract Buydown shall be 2.79% plus its FAME issuance
costs; (ii) the pre-tax return on the unrecovered Seabrook Investment and
approved special rate contract costs shall be 11.74%; and, (iii) the pre-tax
return on the Maine Yankee decommissioning related costs shall be 8.56%.
MPUC Request for Approval of
Alternative Rate Plan
On
March 6, 2003, MPS submitted its formal “Request for Approval of Alternate Rate
Plan” (“ARP”) (MPUC Docket 2003-85). The proposal was a seven-year rate plan
for its distribution delivery services and had a target implementation date on
or before July 1, 2003. The ARP is an alternative form of regulating MPS’s
distribution assets, similar to the performance rate plans the MPUC has adopted
for Central Maine Power Company and Bangor Hydro-Electric Company. In
accordance with a recently enacted state statute, Maine utilities requesting an
ARP must now also file cost of service financial information as part of the ARP
proceeding. In connection with this
aspect of the ARP review and analysis, MPS has been authorized by, and has
received final approval from the MPUC to increase its electric delivery
rates. Following the entry of a
procedural order, discovery, and a public conference, by an Order dated October
29, 2003, the MPUC approved a final Supplemental Stipulation in connection with
this rate increase. As a result,
effective November 1, 2003, MPS increased its total electric delivery rate by 3.78%,
or a total revenue increase not to exceed $1,126,552. This increase includes $685,037 in distribution revenues and
$441,515 in transmission revenues.
Following the entry of the order approving the Supplemental Stipulation,
the ARP proceeding was
Page 74
of 95
bifurcated
and MPS had until December 31, 2003 to notify the MPUC of its intention to
proceed with the remaining elements of the ARP or withdraw the ARP docket. On December 29, 2003, MPS withdrew its
request for approval for its ARP from the proceedings.
FERC Approves Increase in Retail Transmission Rates
The
FERC approved wholesale transmission rates effective June 1, 2002, in FERC
Docket No. ER00-1053, a proceeding related to MPS’s Open Access Transmission
Tariff (“OATT”). On August 6, 2002, MPS
notified the MPUC of its intention to implement the associated transmission
component of its retail T&D rates, with the new rates effective October 1,
2002. The FERC maintains jurisdiction
over all transmission rates. This
implementation increased overall delivery rates by approximately 2%. MPS increased its transmission rates subject
to refund and issuance of a final order by FERC, which was issued in March,
2003.
FERC Open Access Transmission Tariff (“OATT”) Filing
Pursuant
to Section 2.4 of the Settlement Agreement filed on September 30, 2000, in
Docket No. ER00-1053-000, and accepted by the FERC on September 15, 2000, MPS
provided parties and FERC staff on June 10, 2003, the OATT Formula Rate charges
that MPS proposed to apply on June 1, 2003, together with back-up materials. On
June 1, 2003, the Formula Rate charges became effective subject to a refund
that may occur in connection with a settlement stipulation negotiated by the
parties to the proceeding. In general,
MPS is seeking a slight modification to its rate formula under its transmission
tariff, including, among others, changes in certain depreciation rates for
transmission property, and allocations of certain operating expenses and
revenues. The return on common equity
used in determining the rate of return on transmission rate base will remain at
11%. An Order approving the 2003
informational filings and OATT revisions is expected during the first quarter
of 2004. MPS is currently engaged in
discussions with the parties and FERC staff to resolve all outstanding issues
in the filing with the objective of reaching a settlement agreement. In February 2004, the parties executed a
settlement which was filed with the FERC on February 11, 2004.
Seabrook Nuclear Power Project
In
1986, MPS 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 MPS’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, 2003 and 2002 are as follows:
|
|
|
(Dollars
in Thousands)
|
|
|
|
|
2003
|
|
2002
|
|
|
|
|
|
|
|
|
|
Recoverable Seabrook Costs
|
|
$
|
43,136
|
|
$
|
43,136
|
|
|
Accumulated Amortization
|
|
(29,247
|
)
|
(28,137
|
)
|
|
Recoverable Seabrook Costs, Net of
Amortization
|
|
$
|
13,889
|
|
$
|
14,999
|
|
In
March 2000, MPS was allowed to offset $7.0 million of the recoverable Seabrook
costs with the available value from its deferred asset sale gain, as detailed
in “Capacity Arrangements-Generating Asset Sale,” below. The decrease in recoverable Seabrook costs
represents monthly amortization, recorded as amortization expense in January
and February, 2000, and then as stranded costs applied to the deferred asset
sale gain beginning in March, 2000, as described in “MPUC Approves Elements of
Rates Effective March 1, 2000,” above.
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 MPS’s 5% equity ownership in Maine Yankee (see Note 5,
“Investments in Associated Companies”), MPS’s share of any retrospective
premium would not exceed approximately $2.9 million or $.5 million annually,
without considering inflation indexing.
Generating Asset Sale
On
July 7, 1998, MPS and WPS Power Development, Inc., (“WPS-PDI”) signed a purchase
and sale agreement for MPS’s electric generating assets. WPS-PDI agreed to purchase 91.8 megawatts of
generating capacity for $37.4 million, which was 3.2 times higher than the net
book value of the assets. The gain from
the asset sale reduced stranded cost revenue requirements, as discussed in
“MPUC Approves Elements of Rates Effective March 1, 2000,” above.
On
June 8, 1999, after receiving all of the major regulatory approvals, MPS
completed the sale to WPS-PDI for $37.4 million. MPS’s 5% ownership in Maine Yankee was not part of the sale,
since the plant is being decommissioned.
After paying Canadian, Federal and State
Page 75
of 95
income
taxes, the remaining proceeds, along with interest in the trust account, were
used to reduce MPS’s debt. The gain
from the sale was deferred, and recognized according to the MPUC’s decision on
MPS’s determination of stranded costs, transmission and distribution costs, and
rate design. The components of the
deferred gain were as follows:
|
|
|
(Dollars
in Millions)
|
|
|
Gross proceeds *
|
|
$
|
38.6
|
|
|
Settlement adjustments
|
|
(.1
|
)
|
|
Net proceeds
|
|
38.5
|
|
|
Net book value
|
|
(11.5
|
)
|
|
Excess taxes on sale of Canadian Assets
|
|
(3.4
|
)
|
|
Transition costs, net
|
|
(1.9
|
)
|
|
Other
|
|
.7
|
|
|
Available deferred gain
|
|
22.4
|
|
|
Utilization of available value per MPUC orders
|
|
(22.4
|
)
|
|
Remaining deferred gain
|
|
$
|
0
|
|
* Gross proceeds were increased by $1.05
million before tax in September 2001 due to an MPUC approved settlement between
CMP and other former owners of Wyman Unit No. 4, including MPS. The proceeds increased the deferred gain and
further reduced stranded costs.
With
the sale of MPS’s generating assets in June, 1999, MPS purchased energy from
the new owners under an agreement that expired February 29, 2000, and these
purchases are classified as purchased energy.
As
part of the generating asset sale on June 8, 1999, MPS has entered into two
indemnity obligations with the purchaser, WPS-PDI. First, MPS 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,
MPS 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.
Maine Yankee
MPS
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.
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 MPS’s 5% share would be
approximately $46.5 million. On nine
different occasions dating back to December 1998, Maine Yankee has updated its
estimate of decommissioning costs based on the Settlement. Legislation enacted in Maine in 1997 called
for restructuring the electric utility industry and provided 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, MPS believes that it is
entitled to recover substantially all of its share of such costs from its
customers and, as of December 31, 2003, is carrying on its consolidated balance
sheet a regulatory asset and a corresponding liability in the amount of $17.8
million, which reflects MPS’s 5% share of Maine Yankee’s September 2003 revised
estimate of the remaining decommissioning costs, less actual decommissioning
payments made since then, and discounted by a risk-free interest rate.
The
MPUC, on January 27, 2002, approved a Stipulation providing for the recovery of
stranded investment, for a two-year period from March 1, 2002 until February
29, 2004, which includes MPS’s share of Maine Yankee decommissioning expenses,
Maine Yankee replacement power costs, and the remaining Maine Yankee
investment.
As
of December 31, 2003, deferred fuel of $20.5 million is reflected as a
regulatory asset, which includes the Maine Yankee replacement power costs, as
well as deferred Wheelabrator-Sherman fuel costs.
In
accordance with its 1999 FERC rate case settlement, on October 21, 2003, Maine
Yankee filed a revised formula rate schedule with the FERC, proposing an
effective date of January 1, 2004. The
filing contained a revised decommissioning cost estimate and collection
schedule to assure that adequate funds are available to safely and promptly
decommission the Plant and operate and manage the independent spent fuel
storage installation (“ISFSI”). In the filing, Maine Yankee also requested a
change in its billing formula and an increase in the level of collection for
certain post-retirement benefits. To
meet these needs, Maine Yankee proposed to collect an additional $3.77 million
per year over current decommissioning collection levels through October 2008,
exclusive of any income-tax liability, for the decommissioning and spent-fuel
management expense, and to collect from November 2008 through October 2010, the
amounts needed to replenish its Spent Fuel Trust for funds previously used for
ISFSI construction. On December 19,
2003, the FERC issued an order accepting the new rates effective January 1,
2004, subject to refund pending a hearing.
Maine Yankee believes it is entitled to recover the costs underlying the
proposed new rates, but cannot predict the outcome of the rate proceeding.
Page 76
of 95
As
previously reported, in May 2000, Maine Yankee terminated its decommissioning
operations contract with Stone & Webster Engineering Corp. (“Stone &
Webster”) pursuant to the terms of the contract. Stone & Webster disputed Maine Yankee’s grounds for the
termination. In June 2000, Stone &
Webster filed a voluntary petition under Chapter 11 of the United States
Bankruptcy Code with the United States Bankruptcy Court for the District of
Delaware. Since the contract
termination, Maine Yankee has managed the decommissioning project itself.
In
December 2001, Maine Yankee and Federal Insurance Company (“Federal”) entered
into a settlement agreement resolving litigation between the parties, pursuant
to which Federal paid Maine Yankee $44 million. That amount represented full payment under the performance bond
provided by Federal, plus an additional amount under its payment bond
reflecting certain payments previously made by Maine Yankee to subcontractors
and suppliers who had not been fully paid by Stone & Webster. Maine Yankee deposited the payment in its
decommissioning trust fund to offset past and future expenses resulting from
the failures of Stone & Webster.
In
addition, Maine Yankee continued to pursue its claim for damages that was
originally filed against Stone & Webster and its then parent corporations
in August 2000, in the Bankruptcy Court in Delaware. After recognizing the payment from Federal, Maine Yankee asserted
a right to recover an additional $21 million in that court from the bankruptcy
estates. After extensive interim
proceedings and negotiations, in the third quarter of 2003, the major parties
agreed to a joint plan of reorganization under which Maine Yankee would have an
allowed claim of $20.3 million against the principal bankrupt estate, subject
to certain contingencies. Under the
plan, Maine Yankee would also have a first lien on any distributions from a
related bankrupt estate in the proceeding on any amount needed to increase its
actual cash recovery to $18.5 million.
On January 13, 2004, Maine Yankee received an initial distribution of
$8.4 million, which it deposited in its decommissioning trust fund. The amount of cash that Maine Yankee will
actually recover on the balance of its claim remains contingent on a number of
factors beyond Maine Yankee’s control that affect the amount of bankrupt estate
assets ultimately available to pay the claim.
Maine Yankee has settled its litigation claims against Stone &
Webster’s bankruptcy estate and Envirocare in connection with Stone &
Webster’s bankruptcy proceeding.
Federal
legislation enacted in 1987 directed the Department of Energy (“DOE”) to
proceed with the studies necessary to develop and operate a permanent
high-level waste (spent fuel) repository at Yucca Mountain, Nevada. The project
has encountered delays, and the DOE has indicated that the permanent disposal
site is not expected to open before 2010, although originally scheduled to open
in 1998.
In
accordance with the process set forth in the legislation, in February 2002, the
Secretary of Energy recommended the Yucca Mountain site to the President for
the development of a nuclear waste repository, and the President then
recommended development of the site to Congress. As provided in the statutory
procedure, the state of Nevada formally objected to the site in April 2002, and
in July 2002, Congress overrode the objection. Construction of the repository
requires the approval of the Nuclear Regulatory Commission (“NRC”), upon
application of the DOE, and after a public adjudicatory hearing, as well as a
second NRC approval after completion of construction to operate the facility.
Maine Yankee cannot predict the timing or results of those proceedings.
In
November 1997, the U.S. Court of Appeals for the District of Columbia Circuit
confirmed the obligation of the DOE under the Nuclear Waste Policy Act of 1982 to take responsibility
for spent nuclear fuel from commercial reactors in January 1998. After an
unsuccessful effort by Maine Yankee in the same court to compel the DOE to take
Maine Yankee’s spent fuel, in June 1998, Maine Yankee filed a claim for money
damages in the U.S. Court of Federal Claims for the costs associated with the
DOE’s default. In November 1998, the Court granted summary judgment in favor of
Maine Yankee, ruling the DOE had violated its contractual obligations, but
leaving the amount of damages incurred by Maine Yankee for later determination by
the Court. Since then the parties have been engaged in extensive
discovery and resolution of pre-trial issues in the damages phase of the
proceeding. On June 26, 2003, the Court denied three motions for summary
judgment filed by the DOE and indicated in its order that final pretrial
submissions were to be due at the end of September 2003, with a trial to follow
shortly thereafter. However, at the end
of September, the DOE requested an extension of time to complete its discovery,
which was later granted, extending the discovery period to February 12,
2004. Maine Yankee is pursuing its
claim for determination of damages vigorously, but cannot predict the outcome
or timing of the determination.
At
the same time, as an interim measure until the DOE meets its contractual
obligation to dispose of Maine Yankee’s spent fuel at Yucca Mountain or
elsewhere, Maine Yankee constructed an ISFSI, utilizing dry-cask storage, on
the Plant site and has completed the process of transferring the spent fuel
from the spent-fuel pool to the individual casks and the casks to the ISFSI.
Maine Yankee’s total cost of maintaining the ISFSI will be substantially
affected by heightened security costs and by the length of time it is required
to operate the ISFSI before the DOE honors its contractual obligation to take
the fuel from the site. Maine Yankee’s current decommissioning costs
estimate is based on an assumption that its operation of the ISFSI will end in
2023, but the actual period of operation and cost may vary.
On
January 15, 2003, Maine Yankee notified NAC International (“NAC”), the
contractor responsible for providing for the fabrication of the spent-fuel
casks and transferring the fuel to the casks and the casks to the ISFSI, that
Maine Yankee was terminating its contract with NAC pursuant to the terms of the
contract. NAC had been experiencing financial difficulties and had requested
relief from the terms of the contract. Maine Yankee believes that NAC had also
failed to perform its contractual obligations in accordance with the terms of
the contract and provide adequate assurance of its ability to do so in the
future. NAC disputed Maine Yankee’s basis for terminating the contract and
served Maine Yankee with a demand to arbitrate the dispute and a request for
damages. Maine Yankee, in turn, filed suit in the U.S. District Court for
the District of Maine against NAC, its bonding company, and its parent
guarantor, wherein Maine Yankee sought, among other things, damages due to
NAC’s failure to perform. Maine Yankee also entered into contracts with
the major subcontractors and resumed the transfer of fuel to the ISFSI under
its own management.
Page 77
of 95
In
April 2003, after extensive negotiations, the parties entered into a
comprehensive settlement agreement resolving all the disputed issues and
providing for Maine Yankee to replace NAC in managing the completion of the
fuel-transfer work. The settlement included a payment for $10.4 million
to Maine Yankee to compensate Maine Yankee for higher costs incurred or to be
incurred as a result of NAC’s failure to perform its contractual obligations.
The payment was reflected in Maine Yankee’s second quarter 2003 results.
Although the NAC dispute contributed to a slowdown in the progress of the
fuel transfer work in the first quarter of 2003, since then Maine Yankee has
implemented additional efficiencies and the pace of work has improved to a
point where it has been consistently exceeding the pre-2003 pace. The
transfer of spent fuel to the ISFSI was completed in the first quarter of 2004.
The
Federal Low-Level Radioactive Waste Policy Amendments Act, enacted in 1986,
required states, either alone or in multi-state compacts, to provide for the
disposal of low-level radioactive waste generated within their borders.
The States of Maine, Texas and Vermont entered into a compact for the disposal
of low-level waste over a 30 year period at a then-planned facility in west
Texas.
The
terms of the compact provided that the state of Maine would contribute $25
million, payable (1) in two equal installments, the first after ratification by
Congress and the second upon commencement of operation of the Texas facility,
or (2) alternatively, if agreed by the three states, in accordance with the
schedule for repayment of bonds issued for the development or operation of the
facility. By statute, those costs were to be initially assessed against
Maine Yankee, as the operator of a nuclear power plant in Maine. As required by the 1986 Act, the United
States Congress ratified the compact in September 1998. However, in
October 1998, the Texas Natural Resource Conservation Commission denied a
permit for the proposed west Texas site, and efforts to site such a facility in
Texas were suspended. Maine Yankee is shipping its low-level waste to
other facilities licensed to accept such material.
At
its 2002 session, the Maine legislature enacted legislation providing for the
withdrawal of the state of Maine from the Texas compact pursuant to the terms
of the compact. The legislation cited the 1997 closure of the Maine
Yankee plant and the inability of the state of Texas to cause a disposal
facility to be built in a timely manner under the compact as the reasons for
initiating the withdrawal process. However, in its 2003 session, the
Texas legislature enacted a bill that reactivated the process of siting a
disposal facility in Texas and provides for Texas to seek payment from Maine of
$12.5 million under the compact. By
letter dated September 10, 2003, the Attorney General of Texas requested
payment of $12.5 million from the state of Maine, to which the state of Maine
responded by denying liability. Maine Yankee believes that withdrawal
from the compact by the state of Maine is legally justified, but cannot predict
the results of the Texas legislation on the state of Maine or Maine Yankee or
of any attempt by any party to challenge the state of Maine’s withdrawal from
the compact or to assess Maine Yankee for any payments under the compact.
On
February 28, 2003, the Nuclear Regulatory Commission approved Maine Yankee’s
License Termination Plan (“LTP”). The
LTP was approved without any unexpected conditions. In accordance with the plan accepted by the SEC, Maine Yankee has
started the redemption of its common stock periodically through 2008.
MEPCO
MPS
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.
Wheelabrator-Sherman
MPS
was ordered into a Power Purchase Agreement (“PPA”) with Wheelabrator-Sherman
(“WS”) in 1986, which required the purchase of the entire output (up to 126,582
MWH per year) of a 17.6 MW biomass plant through December 31, 2000. The PPA was subsequently amended in 1997,
with WS agreeing to price reductions of $10 million through the end of the
original term in exchange for an up-front payment of $8.7 million in May,
1998. The MPUC’s December, 1997
approval of the amended PPA included a determination that the up-front payment
would be treated as stranded cost and, therefore, recovered in rates of the
transmission and distribution company, as discussed in “MPUC Approves Elements
of Rates Effective March 1, 2000,” above.
Total stranded cost included as a regulatory asset under the caption
“deferred fuel and purchased energy cost” in the accompanying balance sheet
related to this contract is $20.5 million and $13.1 million at December 31,
2003 and 2002, respectively.
MPS
and WS also agreed to renew the PPA for an additional six years at agreed-upon
prices and an increase of output to 136,982 MW beginning in 2001. Energy supply purchases under this contract
through February 29, 2000 were $2.6 million.
As described in “MPUC Approves Elements of Rates Effective March 1,
2000,” above, purchases from WS after March 1, 2000 are reflected as stranded
costs.
MPS
estimates its remaining commitment to purchase power under this contract to be
$35.7 million from January 1, 2004 through 2006. MPS has entered a contract whereby WPS-PDI takes delivery of the
power through February 28, 2002 at market prices, and beginning March 1, 2002
through February 29, 2004, Energy Atlantic, the Company’s wholly-owned marketing
subsidiary, will be taking delivery of 40% of WS’s output and WPS-PDI will take
the remainder. MPS estimates that the
remaining stranded costs will be $21.6 million through 2006, assuming
arrangements similar to the one with WPS-PDI and EA will be in place for that
period.
Page 78
of 95
Construction Program
Expenditures
on additions, replacements and equipment for the years ended December 31, 2003,
2002 and 2001, along with 2004 estimated expenditures, and are as follows:
|
|
|
2004
|
|
2003
|
|
2002
|
|
2001
|
|
|
|
|
(Unaudited
Estimates)
|
|
|
|
|
|
|
|
|
MPS
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
$
|
498
|
|
$
|
224
|
|
$
|
1,007
|
|
$
|
759
|
|
|
Distribution
|
|
2,650
|
|
3,520
|
|
4,004
|
|
3,317
|
|
|
General
|
|
2,644
|
|
865
|
|
911
|
|
608
|
|
|
Total MPS
|
|
5,792
|
|
4,609
|
|
5,922
|
|
4,684
|
|
|
Other Subsidiaries
|
|
0
|
|
268
|
|
6
|
|
23
|
|
|
Total
|
|
$
|
5,792
|
|
$
|
4,877
|
|
$
|
5,928
|
|
$
|
4,707
|
|
Off-Balance Sheet Arrangements
The Company does not have any variable interest
entities as defined by Financial Accounting Standards Board Interpretation No.
46, “Consolidation of Variable Interest Entities,” (“FIN 46”) promulgated on
January 17, 2003 and discussed in the Company’s reports on Form 10-Q for the
quarters ended June 30, 2003 and September 30, 2003. Except for operating leases used for office and field equipment,
vehicles and computer hardware and software, accounted for in accordance with
Financial Accounting Standards No. 13, “Accounting for Leases,” (“FAS 13”) the
Company has no other form of off-balance sheet arrangements. The following summarizes payments for leases
for a period in excess of one year for the years ended December 31, 2003 and
2002:
|
|
|
(Dollars
in Thousands)
|
|
|
|
|
2003
|
|
2002
|
|
|
|
|
|
|
|
|
|
Office Equipment
|
|
$
|
0
|
|
$
|
9
|
|
|
Vehicles
|
|
0
|
|
5
|
|
|
Computer Hardware and Software
|
|
53
|
|
112
|
|
|
Rights of Way
|
|
29
|
|
28
|
|
|
Field Equipment
|
|
21
|
|
30
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
103
|
|
$
|
184
|
|
The
future minimum lease payments for the items listed above for the next five
years are as follows:
Future
Minimum Lease Payments By Year For All Items
|
Years
|
|
Minimum
Lease Payments
|
|
|
|
|
(Dollars
in Thousands)
|
|
|
2004
|
|
$
|
102
|
|
|
2005
|
|
$
|
64
|
|
|
2006
|
|
$
|
52
|
|
|
2007
|
|
$
|
54
|
|
|
2008
|
|
$
|
55
|
|
13. GUARANTOR ARRANGEMENTS
In
November 2002, the FASB issued FIN No. 45, “Guarantor’s Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others an interpretation of FASB Statements No. 5, 57, and 107
and rescission of FASB Interpretation No. 34,” (“FIN 45”). FIN 45 requires that a guarantor recognize,
at the inception of a guarantee, a liability for the fair value of the
obligation undertaken by issuing the guarantee. FIN 45 also requires additional disclosures to be made by a
guarantor in its interim and annual financial statements about its obligations
under certain guarantees it has issued.
The accounting requirements for the initial recognition of guarantees
are applicable on a prospective basis for guarantees issued or modified after
December 31, 2002. The disclosure
requirements are effective for all guarantees outstanding, regardless of when
they were issued or modified for financial statements for interim or annual
periods ending after December 15, 2002.
The adoption of the recognition provisions of FIN 45 are not expected to
have a material effect on the Company’s consolidated financial statements. The following is a summary of our agreements
that management has determined are within the scope of FIN 45.
Page 79
of 95
As
permitted under Maine law, we have agreements whereby we indemnify our officers
and directors for certain events or occurrences while the officer or director
is, or was serving, at our request in such capacity. The term of the indemnification period is for the officer’s or
director’s lifetime. The maximum potential
amount of future payments we could be required to make under these
indemnification agreements is unlimited; however, we have a Director and
Officer insurance policy that limits our exposure and enables us to recover a
portion of any future amounts paid. As
a result of our insurance policy coverage, we believe the estimated fair value
of these indemnification agreements is minimal. All of these indemnification agreements were grandfathered under
the provisions of FIN 45 as they were in effect prior to December 31,
2002. Accordingly, we have no
liabilities recorded for these agreements as of December 31, 2003.
14. ACQUISITIONS
On
December 1, 2003, the Company’s Canadian subsidiary, Maricor acquired all of
the outstanding common shares of Eastcan Consultants, Inc., a closely held
Canadian corporation. The results of
Eastcan’s operations have been included in the consolidated financial
statements since that date. Eastcan is
a mechanical and electrical engineering service firm headquartered in Moncton,
NB, Canada. The acquisition is the Company’s first step towards achieving its
stated strategy of gaining entry to the engineering services sector in the
Maritime provinces of Canada. The
Company expects to increase Eastcan’s revenues by increasing marketing and
business development more than Eastcan would have been able to do by itself.
The
aggregate purchase price was $718,000, consisting of 5,529 shares of MAM common
stock valued at $194,000, $397,000 of cash, $5,000 in unrealized foreign
exchange gain from the date of stock valuation to the closing date, and
$122,000 in external costs for the acquisition. The value of the 5,529 common shares issued was determined based
on the average market price of the Company’s common shares over the 10–day period
ending five day before the acquisition and was $35.01 per share.
The
following table summarizes the estimated fair values of the assets acquired and
liabilities assumed at the date of acquisition. The Company valued the intangible assets as of the date of
acquisition and no further refinement is expected.
At December 1, 2003
($000s)
|
Current assets
|
|
$
|
315
|
|
|
Property, plant, and equipment
|
|
40
|
|
|
Intangible assets
|
|
138
|
|
|
Goodwill
|
|
415
|
|
|
Total assets acquired
|
|
908
|
|
|
Current liabilities
|
|
(190
|
)
|
|
Long-term debt
|
|
(0
|
)
|
|
Total liabilities assumed
|
|
(190
|
)
|
|
Net assets acquired
|
|
$
|
718
|
|
Of
the $138,000 of acquired intangible assets, the Company assigned $30,000 to the
expected profits in the firm contract backlog which is subject to amortization
as the contracts are completed, and should be fully amortized during 2004. The Company assigned $108,000 to the value
of the client list and relationships established by Eastcan. The client list amortization is over a
three-year life.
The
Company assigned the entire goodwill of $415,000 to the unregulated
segment. The goodwill is not deductible
for tax purposes under Canadian tax rules.
Page 80
of 95
15. QUARTERLY INFORMATION (unaudited)
Quarterly
financial data for the two years ended December 31, 2003, reflecting the
beginning of MAM activity in the third quarter and MAMES in the fourth quarter,
are as follows:
|
|
|
(Dollars
in Thousands Except Per Share Amounts)
|
|
|
|
|
2003 by Quarter
|
|
|
|
|
1st
|
|
2nd
|
|
3rd
|
|
4th
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
MAM / MAMES
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
58
|
|
|
Maine Public Service
|
|
9,580
|
|
6,322
|
|
6,823
|
|
9,014
|
|
|
Energy Atlantic
|
|
1,788
|
|
1,699
|
|
1,288
|
|
1,289
|
|
|
Total Revenues
|
|
11,368
|
|
8,021
|
|
8,111
|
|
10,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
9,167
|
|
8,291
|
|
7,786
|
|
9,457
|
|
|
Operating income (loss)
|
|
2,201
|
|
(270
|
)
|
325
|
|
904
|
|
|
Interest charges
|
|
56
|
|
(1
|
)
|
19
|
|
228
|
|
|
Other income (deductions)-net
|
|
(205
|
)
|
33
|
|
(41
|
)
|
161
|
|
|
Net income (loss)
|
|
$
|
1,940
|
|
$
|
(236
|
)
|
$
|
265
|
|
$
|
837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share
|
|
$
|
1.23
|
|
$
|
(.15
|
)
|
$
|
.17
|
|
$
|
.53
|
|
|
|
|
2002 by Quarter
|
|
|
|
|
1st
|
|
2nd
|
|
3rd
|
|
4th
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
Maine Public Service
|
|
$
|
9,599
|
|
$
|
6,401
|
|
$
|
6,583
|
|
$
|
8,818
|
|
|
Energy Atlantic
|
|
1,807
|
|
1,652
|
|
7,553
|
|
1,691
|
|
|
Total Revenues
|
|
11,406
|
|
8,053
|
|
14,136
|
|
10,509
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
9,272
|
|
7,568
|
|
10,533
|
|
9,657
|
|
|
Operating income
|
|
2,134
|
|
485
|
|
3,603
|
|
852
|
|
|
Interest charges
|
|
144
|
|
138
|
|
125
|
|
69
|
|
|
Other income (deductions)-net
|
|
115
|
|
51
|
|
44
|
|
(265
|
)
|
|
Net income
|
|
$
|
2,105
|
|
$
|
398
|
|
$
|
3,522
|
|
$
|
518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share
|
|
$
|
1.34
|
|
$
|
.25
|
|
$
|
2.24
|
|
$
|
.33
|
|
Page 81
of 95
Item 16. Exhibits,
Financial Statement Schedules and
Reports on Form 8-K
(2) Financial Statement Schedules
Included
in Part IV of this report:
Schedule II - Valuation of Qualifying Accounts 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
Exhibits
for Maine Public Service Company are listed in the Index to Exhibits, pages 88
to 94.
Certification
of Financial Reports dated March 29, 2004, for the Form 10-K for the year ended
December 31, 2003.
(b) The following Forms 8-K were filed for MPS:
• January
23, 2003 - Reporting the election of David N. Felch as a Director, described
under Item 5, Other Events.
• February
14, 2003 - Press release dated February 14, 2003 reporting the Company’s
financial results for the fourth quarter of 2002 and for the year 2002, under
Item 7, Financial Statements and Exhibits.
• February
28, 2003, - Reporting the filing of a new alternative rate plan and performance
based rate structure and Energy Atlantic’s focus on Southern Maine markets and
the cessation of marketing in northern Maine, under Item 5, Other Events.
• June
2, 2003 – Reporting on the votes at the Annual Meeting of Stockholders held on
May 30, 2003, approving the reorganization into a holding company and the
election of four directors, as described in Part II, Item 4 above; the
declaration of the quarterly dividend payable July 1, 2003; the election of
officers; the resignation of J. Gregory Freeman and the retirement of J. Paul
Levesque from the Board of Directors.
• July
2, 2003 – Reporting on the reorganization of MPS into a holding company, Maine
& Maritimes Corporation and providing the Interim Report to Stockholders of
Maine & Maritimes Corporation dated July 1, 2003.
The
following Forms 8-K were filed for Maine & Maritimes Corporation:
• June
4, 2003 – Reporting the vote at the MPS Stockholders’ Annual Meeting held on
May 30, 2003, approving the reorganization into a holding company.
• July
1, 2003 – Reporting on the reorganization of MPS into a holding company, Maine
& Maritimes Corporation and providing the Interim Report to Stockholders.
• August
14, 2003 – Press release titled “Maine & Maritimes Corporation Announces
Second Quarter Results.”
• September
5, 2003 – Reporting on the declaration of a regular quarterly dividend by the
Board of Directors and the designation of Michael W. Caron as the Company’s
Audit Committee Financial Expert.
• September
5, 2003 – Reporting that the Company’s wholly-owned electric transmission and
distribution utility, MPS, has been authorized by the Maine Public Utilities
Commission to increase its electric delivery rates.
• September
10, 2003 – Reporting on the implementation of a long-term interest rate stabilization
program through the execution of interest rate swaps.
• October
1, 2003 – Providing the Interim Report to Stockholders dated October 1, 2003,
presenting financial results through August 31, 2003.
Page 82
of 95
• October
30, 2003 – Reporting Maine & Maritimes Subsidiary, MPS, received final
approval from the Maine Public Utilities Commission to increase its electric
delivery rates.
• November
13, 2003 – Press release titled “Maine & Maritimes Corporation’s Third
Quarter Results Exceed Management Expectations.”
• November
17, 2003 – Announcing web cast titled “Maine & Maritimes Corporation
Updates Corporate Progress.”
• November
18, 2003 – Press release titled “Maine & Maritimes Corporation Wins 2003
EEI Index Award for Outstanding Five-Year Stock Results for Small Cap
Companies.”
• December
1, 2003 – Reporting the formation of two new subsidiaries, Maine &
Maritimes Energy Services Company (“MAMES”), a wholly-owned U.S. subsidiary of
the Company and Maricor Ltd, a wholly-owned Canadian subsidiary of MAMES; the
acquisition by Maricor Ltd of Eastcan Consultants, Inc., a New Brunswick,
Canada based full service mechanical and electrical engineering company with an
office in Moncton and Saint John, New Brunswick, Canada.
• December
8, 2003 – Reporting on the declaration of a regular quarterly dividend by the
Board of Directors.
• January
2, 2004 – Providing the Interim Report to Stockholders dated January 1, 2004,
presenting financial results through November 30, 2003.
• March
2, 2004 – Reporting on the Approval by the Maine Public Utilities Commission of
the Stranded Cost Revenue Requirements, effective March 1, 2004.
• March
2, 2004 – Press release titled “Maine & Maritimes Corporation Releases Fourth
Quarter 2003 Results.”
• March
8, 2004 – Reporting on the declaration of a regular quarterly dividend by the
Board of Directors.
• March
15, 2004 – Amendment to March 2, 2004 Form 8-K for the press release titled
“Maine & Maritimes Corporation Releases Fourth Quarter 2003 Results.”
Page 83
of 95
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, hereunto duly authorized, on the 29th of March, 2004.
MAINE
& MARITIMES CORPORATION
|
By:
|
/s/
Larry E. LaPlante
|
|
|
Larry
E. LaPlante
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|
Vice
President, Controller and Chief Accounting Officer
|
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
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Title
|
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Date
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/s/
G. Melvin Hovey
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Chairman
of the Board and Director
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3/25/2004
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(G.
Melvin Hovey)
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/s/
J. Nicholas Bayne
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President
& CEO and Director
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3/26/2004
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(J.
Nicholas Bayne)
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/s/
Robert E. Anderson
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Director
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3/24/2004
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(Robert
E. Anderson)
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/s/ D. James Daigle
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Director
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3/29/2004
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(D.
James Daigle)
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/s/
Richard G. Daigle
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Director
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3/24/2004
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(Richard
G. Daigle)
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/s/
David N. Felch
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Director
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3/26/2004
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(David
N. Felch)
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/s/Michael
W. Caron
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Director
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3/25/2004
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(Michael
W. Caron)
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/s/
Deborah L. Gallant
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Director
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3/25/2004
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(Deborah
L. Gallant)
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/s/
Nathan L. Grass
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Director
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3/24/2004
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(Nathan
L. Grass)
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/s/
Lance A. Smith
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Director
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3/25/2004
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(Lance
A. Smith)
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Page 84
of 95
Schedule II
Maine &
Maritimes Corporation & Subsidiaries
Valuation
of Qualifying Accounts & Reserves
For the
Years Ended December 31, 2003, 2002 and 2001
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Additions
|
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Deductions
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Balance at
Beginning of
Period
|
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Costs
&
Expenses
|
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Recoveries
of
Accounts
Previously
Written Off
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Accounts
Written Off As
Uncollectible
|
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Balance at
End of Period
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Reserve Deducted From Asset To Which It
Applies:
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Allowance for Uncollectible Accounts
|
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2003
|
|
213,882
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297,342
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157,224
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432,766
|
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235,682
|
|
|
|
|
|
|
|
|
|
|
|
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2002
|
|
216,500
|
|
377,774
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|
123,082
|
|
503,474
|
|
213,882
|
|
|
|
|
|
|
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|
|
|
|
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2001
|
|
334,690
|
|
78,820
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|
108,598
|
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305,608
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216,500
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Page 85
of 95
CERTIFICATIONS
Exhibit
31 Rule 13a-14(a)/15d-14(a) Certifications
I,
J. Nicholas Bayne, certify that:
1. I have reviewed this annual report on Form
10-K of Maine & Maritimes Corporation (the registrant);
2. Based on my knowledge, this annual report
does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this annual report;
3. Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods
presented in this annual report;
4. The registrant’s other certifying officers
and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the
registrant and we have:
a) designed such disclosure controls and
procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the
registrant’s disclosure controls and procedures as of a date within 90 days
prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report conclusions
about the effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers
and I have disclosed, based on our most recent evaluation, to the registrant’s
auditors and the audit committee of the registrant’s board of directors:
a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the registrant’s
ability to record, process, summarize and report financial data and have
identified for the registrant’s auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that
involves management or other employees who have significant role in the
registrant’s internal controls; and
6. The registrant’s other certifying officers
and I have indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.
|
|
Dated:
|
March 29, 2004
|
|
|
|
|
|
|
|
|
/s/
J. Nicholas Bayne
|
|
|
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J.
Nicholas Bayne
|
|
|
President
and Chief Executive Officer
|
|
|
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Page 86
of 95
I,
Kurt A. Tornquist, certify that:
1. I have reviewed this annual report on Form
10-K of Maine & Maritimes Corporation (the registrant);
2. Based on my knowledge, this annual report
does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this annual report;
3. Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods
presented in this annual report;
4. The registrant’s other certifying officers
and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the
registrant and we have:
a) designed such disclosure controls and
procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the
registrant’s disclosure controls and procedures as of a date within 90 days
prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report conclusions
about the effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers
and I have disclosed, based on our most recent evaluation, to the registrant’s
auditors and the audit committee of the registrant’s board of directors:
a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the registrant’s
ability to record, process, summarize and report financial data and have
identified for the registrant’s auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that
involves management or other employees who have significant role in the
registrant’s internal controls; and
6. The registrant’s other certifying officers
and I have indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.
|
|
Dated:
|
March 29, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/
Kurt A. Tornquist
|
|
|
|
Kurt
A. Tornquist
|
|
|
Senior
Vice President, Chief Financial Officer and Treasurer
|
|
|
|
|
|
Page 87
of 95
INDEX TO 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)
|
|
Articles
of Incorporation with all amendments through March 22, 2004. (Appendix B to 2003 Form S-4/A)
|
|
|
|
|
|
3(b)
|
|
By-laws
of the Company, as amended through March 22, 2004. (Appendix C to 2003 Form S-4/A)
|
|
|
|
|
|
4(a)
|
|
Indenture
of Mortgage and Deed of Trust defining the rights of the holders of MPS’s
First Mortgage Bonds. (Exhibit 4(a)
to 1980 MPS Form 10-K)
|
|
|
|
|
|
4(b)
|
|
First
Supplemental Indenture. (Exhibit 4(b)
to 1980 MPS Form 10-K)
|
|
|
|
|
|
4(c)
|
|
Second
Supplemental Indenture. (Exhibit 4(c)
to 1980 MPS Form 10-K)
|
|
|
|
|
|
4(d)
|
|
Third
Supplemental Indenture. (Exhibit 4(d)
to 1980 MPS Form 10-K)
|
|
|
|
|
|
4(e)
|
|
Fourth
Supplemental Indenture. (Exhibit 4(e)
to 1980 MPS Form 10-K)
|
|
|
|
|
|
4(f)
|
|
Fifth
Supplemental Indenture. (Exhibit A to
MPS Form 8-K dated May 10, 1968)
|
|
|
|
|
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4(g)
|
|
Sixth
Supplemental Indenture. (Exhibit A to
MPS Form 8-K dated April 10, 1973)
|
|
|
|
|
|
4(h)
|
|
Seventh
Supplemental Indenture. (Exhibit A to
MPS Form 8-K dated November 7, 1975)
|
|
|
|
|
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4(i)
|
|
Eighth
Supplemental Indenture. (Exhibit 4(i)
to 1980 MPS Form 10-K)
|
|
|
|
|
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4(j)
|
|
Ninth
Supplemental Indenture. (Exhibit B to
MPS Form 10-Q for the second quarter of 1978)
|
|
|
|
|
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4(k)
|
|
Tenth
Supplemental Indenture. (Exhibit 4(k)
to 1980 MPS Form 10-K)
|
|
|
|
|
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4(l)
|
|
Eleventh
Supplemental Indenture. (Exhibit 4(l)
to 1982 MPS Form 10-K)
|
|
|
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|
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4(m)
|
|
Indenture
defining the rights of the holders of MPS’s 9 7/8% debentures. (Exhibit A to MPS Form 8-K, dated June 10,
1970)
|
|
|
|
|
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4(n)
|
|
Indenture
defining the rights of the holders of MPS’s 14% debentures. (Exhibit 4(n) to 1982 MPS Form 10-K)
|
|
|
|
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4(o)
|
|
Twelfth
Supplemental Indenture. (Exhibit 4(o)
to MPS Form 10-Q for the quarter ended September 30, 1984)
|
|
|
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4(p)
|
|
Thirteenth
Supplemental Indenture. (Exhibit 4(p)
to MPS Form 10-Q for the quarter ended September 30, 1984)
|
|
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4(q)
|
|
Fourteenth
Supplemental Indenture, Dated July 1, 1985.
(Exhibit 4(q) to 1985 MPS Form 10-K)
|
|
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4(r)
|
|
Fifteenth
Supplemental Indenture, Dated March 1, 1986.
(Exhibit 4(r) to 1985 MPS Form 10-K)
|
|
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|
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4(s)
|
|
Sixteenth
Supplemental Indenture, Dated September 1, 1991. (Exhibit 4(s) to MPS’s 1991 Form 10-K)
|
|
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4(t)
|
|
Seventeenth
Supplemental Indenture, Dated April 1, 1997.
(Exhibit 4(t) to MPS’s 1998 Form 10-K)
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Page 88
of 95
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4(u)
|
|
Eighteenth
Supplemental Indenture, Dated April 1, 1998.
(Exhibit 4(u) to MPS’s 1998 Form 10-K)
|
|
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|
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4(v)
|
|
Nineteenth
Supplemental Indenture, Dated May 1, 1998.
(Exhibit 4(v) to MPS’s 1998 Form 10-K)
|
|
|
|
|
|
4(w)
|
|
Twentieth
Supplemental Indenture, Dated October 1, 2000. (Exhibit 4(w) to MPS’s 2000 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 MPS’s 1980 Form 10-K)
|
|
|
|
|
|
10(a)(2)
|
|
Twentieth
Amendment to Joint Ownership Agreement. (Exhibit 10(a)(6) to MPS’s 1986 Form
10-K)
|
|
|
|
|
|
10(a)(3)
|
|
Twenty-Second
Amendment to Joint Ownership Agreement.
(Exhibit 10(a)(3) to the 1988 MPS Form 10-K)
|
|
|
|
|
|
10(b)(1)
|
|
Capital
Funds Agreement, dated as of May 20, 1968 between Maine Yankee Atomic Power
Company and MPS. (Exhibit 10(b)(1) to
MPS 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 MPS. (Exhibit 10(b)(2) to MPS
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 MPS Form 10-Q for the
quarter ended March 31, 1983)
|
|
|
|
|
|
10(c)(2)
|
|
Agreement,
as of June 20, 1969, among MPS and the other Maine Participants. (Exhibit 10(c)(2) to MPS 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 MPS 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 MPS 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 MPS 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 MPS. (Exhibit 10(c)(6) to MPS 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 MPS. (Exhibit
10(c)(7) to MPS 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
MPS. (Exhibit 10(c)(8) to MPS Form
10-Q for the quarter ended March 31, 1983)
|
Page 89
of 95
|
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 MPS
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 MPS Form 10-K)
|
|
|
|
|
|
10(f)
|
|
Credit
Agreement, dated as of October 8, 1987 among MPS 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 MPS 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 MPS 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 MPS Form 8-K dated September 22, 1989)
|
|
|
|
|
|
10(h)
|
|
Amendment
No. 2, dated as of June 5, 1992, to the Revolving Credit Agreement, among MPS
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 MPS’s 1992 Form 10-K)
|
|
|
|
|
|
10(i)
|
|
Indenture
of Second Mortgage and Deed of Trust, dated as of October 1, 1985, made by
MPS to J. Henry Schroder Bank and Trust Company, as Trustee. (Exhibit 10(i) to MPS Form 8-K dated
November 1, 1985)
|
|
|
|
|
|
10(j)
|
|
First
Supplemental Indenture of the Second Mortgage and Deed of Trust Dated March
1, 1991. (Exhibit 10(i) to MPS’s 1991
Form 10-K)
|
|
|
|
|
|
10(k)
|
|
Second
Supplemental Indenture of the Second Mortgage and Deed of Trust Dated
September 1, 1991. (Exhibit 10(j) to
MPS’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 MPS 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 MPS to
Continental Illinois National Bank and Trust Company, as Trustee. (Exhibit 10(j) to MPS Form 8-K dated
November 1, 1985)
|
|
|
|
|
|
10(q)
|
|
Employment
Contract between William L. Cyr and Maine Public Service Company, dated
November 5, 1999. (Exhibit 10(q) to
1999 MPS Form 10-K)
|
|
|
|
|
|
10(s)
|
|
Maine
Public Service Company, Prior Service Executive Retirement Plan, dated May
12, 1992. (Exhibit 10(s) to 1992 MPS
Form 10-K)
|
|
|
|
|
|
10(t)
|
|
Maine
Public Service Company Pension Plan.
(Exhibit 10(t) to 1992 MPS Form 10-K)
|
|
|
|
|
|
10(u)
|
|
Maine
Public Service Company Retirement Savings Plan. (Exhibit 10(u) to 1992 MPS Form 10-K)
|
|
|
|
|
|
10(v)
|
|
Third
Supplemental Indenture of the Second Mortgage and Deed of Trust Dated as of
June 1, 1996. (Exhibit 10(t) to 1996
MPS Form 10-K)
|
|
|
|
|
|
10(w)
|
|
Amendment
No. 3, dated as of October 8, 1995, to the Revolving Credit Agreement, dated
as of October 7, 1987, among MPS 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)
|
|
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10(x)
|
|
Fourth
Supplemental Indenture of the Second Mortgage and Deed of Trust dated May 1,
1998. (Exhibit 10(v) to MPS’s 1998
Form 10-K)
|
Page 90
of 95
|
10(y)
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|
Fifth
Supplemental Indenture of the Second Mortgage and Deed of Trust dated October
1, 2000. (Exhibit 10(y) to MPS’s 2000 Form 10-K)
|
|
|
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|
|
10(z)
|
|
Agreement
between WPS Power Development, Inc. and Maine Public Service Company, dated
July 7, 1998. (Exhibit 10(w) to MPS’s
1998 Form 10-K)
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|
|
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|
10(aa)
|
|
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 MPS’s 1998
Form 10-K)
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|
10(ab)
|
|
Agreement
between Loring Development Authority of Maine and Maine Public Service
Company, dated July 9, 1998. (Exhibit
10(y) to MPS’s 1998 Form 10-K)
|
|
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|
10(ac)
|
|
Wholesale
Power Sales Agreement between Energy Atlantic, LLC and Engage Energy US,
L.P., dated December 9, 1999, with amendments dated March 10, 2000 and August
1, 2000 and addendums dated December 14, 1999 and December 1, 2000. (Exhibit 10(ac) to MPS’s 2000 Form 10-K)
|
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|
10(ad)
|
|
Fourth
Amendment to Wholesale Power Agreement between Energy Atlantic, LLC and
Engage Energy US, L.P., dated June 26, 2001.
(Exhibit 99.2 to MPS’s May 24, 2001 Form 8-K)
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|
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|
10(ae)
|
|
General
Release Agreements between Engage Energy America, LLC, Energy Atlantic, LLC
(EA), Maine Public Service Co., Central Maine Power Company (CMP) and Frontier
Insurance Company (Frontier) for any and all claims under or in connection
with any Bonds issued by Frontier in connection with EA’s provision of the
standard offer service in the service territory of CMP in Maine, both dated
May 24, 2001.
|
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|
|
10(af)
|
|
Master
Power Purchase & Sale Agreement between Energy Atlantic, LLC and Duke
Energy Trading and Marketing, LLC dated September 19, 2001.
|
|
|
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|
10(ag)
|
|
Sixth
Supplemental Indenture of the Second Mortgage and Deed of Trust dated June 1,
2002. (Exhibit 10.1 to MPS’s Form
10-Q for the quarter ended June 30, 2002).
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|
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|
10(ah)
|
|
Stock
Option Grant Agreement dated June 1, 2002.
(Exhibit 10.2 to MPS’s Form 10-Q for the quarter ended June 30, 2002.)
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10(ai)
|
|
Employee
Continuity Agreement between James Nicholas Bayne and Maine Public Service
Company dated July 25, 2002. (Exhibit
10.3 to MPS’s Form 10-Q for the quarter ended June 30, 2002.)
|
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|
*10(aj)
|
|
Interest
Rate Swap Confirmation for 1996 Tax-Exempt Bonds, dated September 9, 2003.
|
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|
*10(ak)
|
|
Interest
Rate Swap Confirmation for 1998 FAME Note, dated September 9, 2003.
|
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|
|
*10(al)
|
|
Interest
Rate Swap Confirmation for 2000 Tax-Exempt Bonds, dated September 9, 2003
|
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|
|
*10(am)
|
|
Temporary
Line of Credit with Bank of New York, dated October 1, 2003.
|
|
|
|
|
|
*10(an)
|
|
Assignment
and Amendment Agreement to Employee Retention Agreement between J. Nicholas
Bayne and Maine & Maritimes Corporation and Maine Public Service Company,
dated October 3, 2003.
|
|
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|
|
*10(ao)
|
|
Employee
Retention Agreement between Kurt A. Tornquist and Maine & Maritimes
Corporation, dated September 5, 2003.
|
|
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|
|
|
*10(ap)
|
|
Employee
Retention Agreement between Larry E. LaPlante and Maine & Maritimes
Corporation, dated September 5, 2003.
|
Page 91
of 95
|
*10(aq)
|
|
Employee
Retention Agreement between John P. Havrilla and Maine & Maritimes
Corporation, dated September 5, 2003.
|
|
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|
*10(ar)
|
|
Employee
Retention Agreement between Michael A. Thibodeau and Maine & Maritimes
Corporation, dated September 5, 2003.
|
|
|
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|
|
*10(as)
|
|
Employee
Retention Agreement between Brent M. Boyles and Maine Public Service Company,
dated September 5, 2003.
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|
*10(at)
|
|
Employee
Continuity Agreement between Calvin D. Deschene and Maine Public Service
Company, dated May 9, 2000.
|
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|
*21
|
|
Subsidiaries
of the Company
|
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|
*31
|
|
Rule
13a-14(a)/15d-14(a) Certifications
|
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|
|
*32
|
|
Certification
of Financial Reports Pursuant to 18 USC Section 1350
|
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|
99(a)
|
|
Agreement
of Purchase and Sale between Maine Public Service and Eastern Utilities Associates,
dated April 7, 1986. (Exhibit 28(a)
to MPS Form 10-Q for the quarter ended June 30, 1986)
|
|
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|
|
99(b)
|
|
Addendum
to Agreement of Purchase and Sale, dated June 26, 1986. (Exhibit 28(b) to MPS Form 10-Q for the
Quarter ended June 30, 1986)
|
|
|
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|
|
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 MPS Form 10-Q for the quarter ended June 30,
1986)
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|
|
99(d)
|
|
Amendment
to July 14, 1986 Stipulation, dated July 18, 1986. (Exhibit 28(d) to MPS Form 10-Q for the quarter ended June 30,
1986)
|
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|
|
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 MPS Form 10-K)
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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 MPS Form 10-K)
|
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|
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 MPS Form 10-K)
|
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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 MPS Form 10-K)
|
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|
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 MPS Form 10-K)
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|
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
MPS Form 10-K)
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|
99(k)
|
|
Order
of Maine Public Utilities Commission dated June 26, 1996 in Docket 95-052
(Rate Design). (Exhibit 99(n) to 1996
MPS Form 10-K)
|
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|
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 MPS Form 10-K)
|
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|
|
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 MPS, 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 MPS Form 10-K)
|
Page 92
of 95
|
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 MPS, the signatory Banks thereto and The
Bank of New York, as Agent. (Exhibit
99(n) to 1997 MPS Form 10-K)
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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 MPS Form 10-K)
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99(p)
|
|
Order
by the Maine Public Utilities Commission dated January 15, 1998 in Docket No.
97-727. (Exhibit 99(q) to 1997 MPS
Form 10-K)
|
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|
99(q)
|
|
Order
of Maine Public Utilities Commission dated February 20, 1998 in Docket 97-670
(Divestiture of Generation Assets).
(Exhibit 99(q) to MPS’s 1998 Form 10-K)
|
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|
99(r)
|
|
Order
of Maine Public Utilities Commission dated September 21, 1998 in Docket
98-138 (Formation of marketing affiliate).
(Exhibit 99(r) to MPS’s 1998 Form 10-K)
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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 MPS’s 1998 Form 10-K)
|
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|
|
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 MPS’s 1998 Form 10-K)
|
|
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|
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
MPS’s 1998 Form 10-K)
|
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|
|
99(v)
|
|
Order
of the Federal Energy Regulatory Commission dated December 22, 1998 in Docket
No. ER95-836-000. (Exhibit 99(v) to
MPS’s 1998 Form 10-K)
|
|
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|
|
|
99(w)
|
|
Order
of Maine Public Utilities Commission dated April 5, 1999 in Docket 98-584
(Generating Asset Sale Approval).
(Exhibit 99(w) to 1999 MPS Form 10-K)
|
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|
|
99(x)
|
|
Order
of the Federal Energy Regulatory Commission dated April 14, 1999 in Docket EC
99-29-000 (Generating Asset Sale Approval).
(Exhibit 99(x) to 1999 MPS Form 10-K)
|
|
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|
99(y)
|
|
Order
of the Federal Energy Regulatory Commission dated November 15, 1999 in Docket
ER 99-4225-000 (Independent System Administrator). (Exhibit 99(y) to 1999 MPS Form 10-K)
|
|
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|
|
99(z)
|
|
Order
of Maine Public Utilities Commission dated December 1, 1999 in Docket 98-577
(Stipulation Approval). (Exhibit
99(z) to 1999 MPS Form 10-K)
|
|
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|
|
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). (Exhibit 99(aa) to 1999 MPS Form 10-K)
|
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|
|
99(ab)
|
|
Order
of Maine Public Utilities Commission dated February 17, 2000 in Docket 98-577
(Order Approving Phase II Stipulation).
(Exhibit 99(ab) to 1999 MPS Form 10-K)
|
|
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|
99(ac)
|
|
Order
of the Federal Energy Regulatory Commission dated August 14, 2000 in Dockets
ER00-1053-000 and ER00-1053-002.
(Exhibit 99(ac) to MPS’s 2000 Form 10-K)
|
|
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|
|
99(ad)
|
|
Order
of the Maine Public Utilities Commission dated November 17, 1999 in Docket
99-610 (Reduction in Capital).
(Exhibit 99(ad) to MPS’s 2000 Form 10-K)
|
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|
|
99(ae)
|
|
Order
of the Maine Public Utilities Commission dated August 11, 2000 in Docket
99-185 (Stipulation Approval).
(Exhibit 99(ae) to MPS’s 2000 Form 10-K)
|
Page 93
of 95
|
99(af)
|
|
Agreement
between the Maine Public Utilities Commission, MPS, Central Maine Power
Company and Bangor Hydro-Electric Company dated January 10, 2001 regarding
Maine Yankee Power Costs. (Exhibit
99(af) to MPS’s 2000 Form 10-K)
|
|
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99(ag)
|
|
Notice
of Investigation of the Maine Public Utilities Commission dated May 8, 2001
in Docket 01-245 (Rate Design)
|
|
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|
|
99(ah)
|
|
Order
of the Maine Public Utilities Commission dated May 24, 2001 in Docket No.
99-764 (Amendments to Entitlement Agreements and Granting Waiver). (Exhibit
99.1 to the May 24, 2001 MPS Form 8-K)
|
|
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|
99(ai)
|
|
Procedural
Order of the Maine Public Utilities Commission dated July 13, 2001 in Docket
No. 00-894 (WPS Energy Service Complaint and related Proposed Findings and
Decision of Investigator William B. Devoe, Esq.)
|
|
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|
99(aj)
|
|
Order
of the Maine Public Utilities Commission dated November 20, 2001 in Docket
No. 01-384 (Entitlement Agreements).
|
|
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|
99(ak)
|
|
Further
Settlement Agreement between the Maine Public Utilities Commission, the
Public Advocate and MPS dated January 24, 2002 regarding Maine Yankee Power
costs.
|
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|
99(al)
|
|
Order
of the Maine Public Utilities Commission dated February 27, 2002 in Docket
No. 01-240 (Stranded Costs Stipulation approved effective March 1, 2002).
|
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|
|
99(an)
|
|
Order
of Maine Public Utilities Commission dated April 29, 2002 in Docket No.
2000-894 approving revised stipulation of WPS Complaint Settlement. (Exhibit 99.1 to MPS’s Form 10-Q for the
quarter ended March 31, 2002.)
|
|
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|
|
*99(ao)
|
|
Order
dated March 26, 2003 of Maine Public Utilities Commission in Docket No.
2002-676 approving reorganization
|
|
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|
|
|
*99(ap)
|
|
Order
dated October 29, 2003 of Maine Public Utilities Commission in Docket No.
2003-85 giving final approval to increase in MPS electric delivery rates
|
|
|
|
|
|
*99(aq)
|
|
Settlement
Agreement dated February 11, 2004, among, MPS, other parties, FERC Trial
Staff, and the MPUC regarding
changes to the MPS Formula Rate under the FERC Open Access Transmission
Tariff.
|
|
|
|
|
|
99(ar)
|
|
Stipulation
dated February 19, 2004, approved by order dated February 27, 2004 of Maine
Public Utilities Commission dated April 29, 2002 in Docket No. 2003-666
approving stranded cost revenue requirements effective March 1, 2004 (Exhibit
99 to Form 8-K dated March 2, 2004)
|
Page 94
of 95
Glossary of Terms
|
AFUDC
|
|
Allowances
for the cost of equity and borrowed funds used during construction
|
|
AMEX
|
|
American
Stock Exchange
|
|
APBO
|
|
Accumulated
Pension Benefit Obligation
|
|
ARP
|
|
Alternative
Rate Plan
|
|
BHE
|
|
Bangor
Hydro Electric Company
|
|
CES
|
|
Competitive
Energy Supplier
|
|
CMLTD
|
|
Current
Maturities Long-Term Debt
|
|
CMP
|
|
Central
Maine Power Company
|
|
DETM
|
|
Duke
Energy Trading and Marketing
|
|
DOE
|
|
Department
of Energy
|
|
EA
|
|
Energy
Atlantic, LLC
|
|
Engage
|
|
Engage
Energy America, LLC
|
|
EPS
|
|
Earnings
Per Share
|
|
FAME
|
|
Finance
Authority of Maine
|
|
FAS
|
|
Financial
Accounting Standards
|
|
FASB
|
|
Financial
Accounting Standards Board
|
|
FERC
|
|
Federal
Energy Regulatory Commission
|
|
FIN
|
|
FASB
Interpretation Number
|
|
ISFSI
|
|
Independent
Spent Fuel Storage Installation
|
|
ISO
|
|
Independent
System Operator
|
|
ISO-NE
|
|
Independent
System Operator – New England
|
|
LIBOR
|
|
London
InterBank Offering Rate
|
|
LOC
|
|
Letter
of Credit
|
|
MAM
|
|
Maine
& Maritimes Corporation
|
|
MAMES
|
|
Maine
& Maritimes Energy Services Company
|
|
Maricor
|
|
Maricor
Ltd.
|
|
Me&NB
|
|
Maine
& New Brunswick Electrical Power Company, Ltd
|
|
MEPCO
|
|
Maine
Electric Power Company, Inc.
|
|
MPS
|
|
Maine
Public Service Company
|
|
MPUC
|
|
Maine
Public Utilities Commission
|
|
MPUFB
|
|
Maine
Public Utility Financing Bank
|
|
MW
|
|
Megawatt
|
|
MWH
|
|
Megawatt
hour
|
|
NEPOOL
|
|
New
England Power Pool
|
|
NMISA
|
|
Northern
Maine Independent System Administrator
|
|
NOI
|
|
Notice
of Inquiry
|
|
NPCC
|
|
Northeastern
Power Coordinating Council
|
|
NRC
|
|
Nuclear
Regulatory Commission
|
|
NUG
|
|
Non-Utility
Generator
|
|
OATT
|
|
Open
Access Transmission Tariff
|
|
PBR’S
|
|
Performance
Based Rates
|
|
PCB
|
|
Poly
Chlorinated Bi-phenol
|
|
PPA
|
|
Power
Purchase Agreement
|
|
PURPA
|
|
Public
Utilities Regulatory Policy Act
|
|
PWC
|
|
PricewaterhouseCoopers
|
|
QF
|
|
Qualifying
Facility
|
|
ROCE
|
|
Return
on Capital Employed
|
|
RTO
|
|
Regional
Transmission Organization
|
|
SAM
|
|
Strategic
Asset Management
|
|
SCADA
|
|
Supervisory
Control and Data Acquisition
|
|
SEC
|
|
Securities
and Exchange Commission
|
|
SFAS
|
|
Statement
of Financial Accounting Standards
|
|
SOS
|
|
Standard
Offer Service
|
|
T&D
|
|
Transmission
and Distribution
|
|
VEBA
|
|
Voluntary
Employee Benefit Association
|
|
VERP
|
|
Voluntary
Employee Retirement Program
|
|
WPS-PDI
|
|
WPS
– Power Development, Inc.
|
|
WS
|
|
Wheelabrator-Sherman
|
Page 95
of 95