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American Electric Power Company 10-K 2007 Documents found in this filing:
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
___________________
FORM
10-K
___________________
(Mark
One)
For
the
fiscal year ended December 31, 2006
For
the
transition period from __________ to_________
AEP
Generating Company, AEP Texas Central Company, AEP Texas North Company, Columbus
Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company
and Public Service Company of Oklahoma meet the conditions set forth in General
Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form
10-K
with the reduced disclosure format specified in General Instruction I(2) to
such
Form 10-K.
Securities
registered pursuant to Section 12(b) of the Act:
Securities
registered pursuant to Section 12(g) of the Act:
Note
On Market Value Of Common Equity Held By Non-Affiliates
American
Electric Power Company, Inc. owns, directly or indirectly, all of the common
stock of AEP Generating Company, AEP Texas Central Company, AEP Texas North
Company, Appalachian Power Company, Columbus Southern Power Company, Indiana
Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public
Service Company of Oklahoma and Southwestern Electric Power Company (see Item
12
herein). Documents
Incorporated By Reference
This
combined Form 10-K is separately filed by AEP Generating Company, AEP Texas
Central Company, AEP Texas North Company, American Electric Power Company,
Inc.,
Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan
Power Company, Kentucky Power Company, Ohio Power Company, Public Service
Company of Oklahoma and Southwestern Electric Power Company. Information
contained herein relating to any individual registrant is filed by such
registrant on its own behalf. Except for American Electric Power Company, Inc.,
each registrant makes no representation as to information relating to the other
registrants.
You
can access financial and other information at AEP’s website, including AEP’s
Principles of Business Conduct (which also serves as a code of ethics applicable
to Item 10 of this Form 10-K), certain committee charters and Principles of
Corporate Governance. The address is www.AEP.com. AEP makes available, free
of
charge on its website, copies of its annual report on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K and amendments to those
reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 as soon as reasonably practicable after filing such
material electronically or otherwise furnishing it to the
SEC.
TABLE
OF CONTENTS
GLOSSARY
OF TERMS
The
following abbreviations or acronyms used in this Form 10-K are defined
below:
FORWARD-LOOKING
INFORMATION
This
report made by AEP and certain of its registrant subsidiaries contains
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934. Although AEP and each of its registrant subsidiaries
believe that their expectations are based on reasonable assumptions, any such
statements may be influenced by factors that could cause actual outcomes and
results to be materially different from those projected. Among the factors
that
could cause actual results to differ materially from those in the
forward-looking statements are:
PART
I
ITEM
1. BUSINESS
GENERAL
OVERVIEW
AND DESCRIPTION OF SUBSIDIARIES
AEP
was
incorporated under the laws of the State of New York in 1906 and reorganized
in
1925. It is a public utility holding company that owns, directly or indirectly,
all of the outstanding common stock of its public utility subsidiaries and
varying percentages of other subsidiaries.
The
service areas of AEP’s public utility subsidiaries cover portions of the states
of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee,
Texas, Virginia and West Virginia. The generating and transmission facilities
of
AEP’s public utility subsidiaries are interconnected and their operations are
coordinated. Transmission networks are interconnected with extensive
distribution facilities in the territories served. The public utility
subsidiaries of AEP have traditionally provided electric service, consisting
of
generation, transmission and distribution, on an integrated basis to their
retail customers. Restructuring legislation in Michigan, Ohio, the ERCOT area
of
Texas and, as of December 31, 2006, Virginia has caused AEP public utility
subsidiaries in those states to unbundle previously integrated regulated rates
for their retail customers.
The
AEP
System is an integrated electric utility system. As a result, the member
companies of the AEP System have contractual, financial and other business
relationships with the other member companies, such as participation in the
AEP
System savings and retirement plans and tax returns, sales of electricity and
transportation and handling of fuel. The member companies of the AEP System
also
obtain certain accounting, administrative, information systems, engineering,
financial, legal, maintenance and other services at cost from a common provider,
AEPSC.
At
December 31, 2006, the subsidiaries of AEP had a total of 20,442 employees.
Because it is a holding company rather than an operating company, AEP has no
employees. The public utility subsidiaries of AEP are:
APCo (organized
in Virginia in 1926) is engaged in the generation, transmission and distribution
of electric power to approximately 949,000 retail customers in the southwestern
portion of Virginia and southern West Virginia, and in supplying and marketing
electric power at wholesale to other electric utility companies, municipalities
and other market participants. At December 31, 2006, APCo and its wholly owned
subsidiaries had 2,461 employees. Among the principal industries served by
APCo
are coal mining, primary metals, chemicals and textile mill products. In
addition to its AEP System interconnections, APCo also is interconnected with
the following unaffiliated utility companies: Carolina Power & Light
Company, Duke Energy Corporation and Virginia Electric and Power Company. APCo
has several points of interconnection with TVA and has entered into agreements
with TVA under which APCo and TVA interchange and transfer electric power over
portions of their respective systems. APCo is a member of PJM.
CSPCo (organized
in Ohio in 1937, the earliest direct predecessor company having been organized
in 1883) is engaged in the generation, transmission and distribution of electric
power to approximately 742,000 retail customers in Ohio, and in supplying and
marketing electric power at wholesale to other electric utilities,
municipalities and other market participants. At December 31, 2006, CSPCo had
1,233 employees. CSPCo’s service area is comprised of two areas in Ohio, which
include portions of twenty-five counties. One area includes the City of Columbus
and the other is a predominantly rural area in south central Ohio. Among the
principal industries served are food processing, chemicals, primary metals,
electronic machinery and paper products. In addition to its AEP System
interconnections, CSPCo also is interconnected with the following unaffiliated
utility companies: CG&E, DP&L and Ohio Edison Company. CSPCo is a member
of PJM.
I&M (organized
in Indiana in 1925) is engaged in the generation, transmission and distribution
of electric power to approximately 582,000 retail customers in northern and
eastern Indiana and southwestern Michigan, and in supplying and marketing
electric power at wholesale to other electric utility companies, rural electric
cooperatives, municipalities and other market participants. At December 31,
2006, I&M had 2,643 employees. Among the principal industries served are
primary metals, transportation equipment, electrical and electronic machinery,
fabricated metal products, rubber and miscellaneous plastic products and
chemicals and allied products. Since 1975, I&M has leased and operated the
assets of the municipal system of the City of Fort Wayne, Indiana. In addition
to its AEP System interconnections, I&M also is interconnected with the
following unaffiliated utility companies: Central Illinois Public Service
Company, CG&E, Commonwealth Edison Company, Consumers Energy Company,
Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas
and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc.
and Richmond Power & Light Company. I&M is a member of PJM.
KPCo (organized
in Kentucky in 1919) is engaged in the generation, transmission and distribution
of electric power to approximately 176,000 retail customers in an area in
eastern Kentucky, and in supplying and marketing electric power at wholesale
to
other electric utility companies, municipalities and other market participants.
At December 31, 2006, KPCo had 466 employees. In addition to its AEP System
interconnections, KPCo also is interconnected with the following unaffiliated
utility companies: Kentucky Utilities Company and East Kentucky Power
Cooperative Inc. KPCo is also interconnected with TVA. KPCo is a member of
PJM.
Kingsport
Power Company (organized
in Virginia in 1917) provides electric service to approximately 46,000 retail
customers in Kingsport and eight neighboring communities in northeastern
Tennessee. Kingsport Power Company does not own any generating facilities and
is
a member of PJM. It purchases electric power from APCo for distribution to
its
customers. At December 31, 2006, Kingsport Power Company had 60 employees.
OPCo (organized
in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation,
transmission and distribution of electric power to approximately 712,000 retail
customers in the northwestern, east central, eastern and southern sections
of
Ohio, and in supplying and marketing electric power at wholesale to other
electric utility companies, municipalities and other market participants. At
December 31, 2006, OPCo had 2,330 employees. Among the principal industries
served by OPCo are primary metals, rubber and plastic products, stone, clay,
glass and concrete products, petroleum refining and chemicals. In addition
to
its AEP System interconnections, OPCo also is interconnected with the following
unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating
Company, DP&L, Duquesne Light Company, Kentucky Utilities Company,
Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and
West Penn Power Company. OPCo is a member of PJM.
PSO (organized
in Oklahoma in 1913) is engaged in the generation, transmission and distribution
of electric power to approximately 520,000 retail customers in eastern and
southwestern Oklahoma, and in supplying and marketing electric power at
wholesale to other electric utility companies, municipalities, rural electric
cooperatives and other market participants. At December 31, 2006, PSO had 1,233
employees. Among the principal industries served by PSO are natural gas and
oil
production, oil refining, steel processing, aircraft maintenance, paper
manufacturing and timber products, glass, chemicals, cement, plastics, aerospace
manufacturing, telecommunications, and rubber goods. In addition to its AEP
System interconnections, PSO also is interconnected with Ameren Corporation,
Empire District Electric Co., Oklahoma Gas & Electric Co., Southwestern
Public Service Co. and Westar Energy Inc. PSO is a member of SPP.
SWEPCo (organized
in Delaware in 1912) is engaged in the generation, transmission and distribution
of electric power to approximately 456,000 retail customers in northeastern
Texas, northwestern Louisiana and western Arkansas, and in supplying and
marketing electric power at wholesale to other electric utility companies,
municipalities, rural electric cooperatives and other market participants.
At
December 31, 2006, SWEPCo had 1,545 employees. Among the principal industries
served by SWEPCo are natural gas and oil production, petroleum refining,
manufacturing of pulp and paper, chemicals, food processing, and metal refining.
The territory served by SWEPCo also includes several military installations,
colleges, and universities. SWEPCO also owns and operates a lignite coal mining
operation. In addition to its AEP System interconnections, SWEPCo is also
interconnected with CLECO Corp., Empire District Electric Co., Entergy Corp.
and
Oklahoma Gas & Electric Co. SWEPCo is a member of SPP.
TCC
(organized
in Texas in 1945) is engaged in the transmission and distribution of electric
power to approximately 738,000 retail customers through REPs in southern Texas.
Under the Texas Act, TCC has completed the final stage of exiting the generation
business and has sold all of its generation assets. At December 31, 2006, TCC
had 1,224 employees. Among the principal industries served by TCC are oil and
gas extraction, food processing, apparel, metal refining, chemical and petroleum
refining, plastics, and machinery equipment. In addition to its AEP System
interconnections, TCC is a member of ERCOT.
TNC (organized
in Texas in 1927) is engaged in the transmission and distribution of electric
power to approximately 189,000 retail customers through REPs in west and central
Texas. TNC’s remaining generating capacity that is not deactivated has been
transferred to an affiliate at TNC’s cost pursuant to a 20-year agreement. At
December 31, 2006, TNC had 386 employees. Among the principal industries served
by TNC are agriculture and the manufacturing or processing of cotton seed
products, oil products, precision and consumer metal products, meat products
and
gypsum products. The territory served by TNC also includes several military
installations and correctional facilities. In addition to its AEP System
interconnections, TNC is a member of ERCOT.
WPCo
(organized
in West Virginia in 1883 and reincorporated in 1911) provides electric service
to approximately 41,000 retail customers in northern West Virginia. WPCo does
not own any generating facilities. WPCo is a member of PJM. It purchases
electric power from OPCo for distribution to its customers. At December 31,
2006, WPCo had 61 employees.
AEGCo (organized
in Ohio in 1982) is an electric generating company. AEGCo sells power at
wholesale to I&M and KPCo. AEGCo has no employees.
SERVICE
COMPANY SUBSIDIARY
AEP
also
owns a service company subsidiary, AEPSC. AEPSC provides accounting,
administrative, information systems, engineering, financial, legal, maintenance
and other services at cost to the AEP System companies. The executive officers
of AEP and certain of its public utility subsidiaries are employees of AEPSC.
At
December 31, 2006, AEPSC had 5,961 employees.
CLASSES
OF SERVICE
The
principal classes of service from which the public utility subsidiaries of
AEP
derive revenues and the amount of such revenues during the year ended December
31, 2006 are as follows:
EPACT
AND THE REPEAL OF PUHCA
EPACT
was
signed into law on August 8, 2005. Among other things, EPACT repealed PUHCA,
effective February 8, 2006. PUHCA regulated many significant aspects of a
registered holding company system, such as the AEP System. PUHCA limited the
operations of a registered holding company system to a single integrated public
utility system and such other businesses as were incidental or necessary to
the
operations of the system. PUHCA also required that transactions between
associated companies in a registered holding company system be performed at
cost, with limited exceptions. As a result of PUHCA’s repeal, utility holding
companies, including the AEP system, are no longer limited to a single
integrated public utility system. Further, utility holding companies are no
longer restricted from acquiring businesses that may not be related to the
utility business. Jurisdiction over certain holding company related activities
has been transferred to the FERC, including the issuances of securities by
public utilities, the acquisition of securities of utilities, the acquisition
or
sale of certain utility assets, and mergers with another electric utility or
holding company. In addition, both FERC and state regulators will be permitted
to review the books and records of any company within a holding company system.
EPACT
contains key provisions affecting the electric power industry. These provisions
include tax changes for the utility industry, incentives for emissions
reductions and federal insurance and incentives to build new nuclear power
plants. It gives the FERC “backstop” transmission siting authority as well as
increased utility merger oversight. The law also provides incentives and funding
for clean coal technologies and initiatives to voluntarily reduce greenhouse
gases. FERC has issued regulations implementing EPACT. We do not expect
compliance with these regulations to have a material adverse impact on our
financial condition and results of operations.
FINANCING
General
Companies
within the AEP System generally use short-term debt to finance working capital
needs. Short-term debt is also used to finance acquisitions, construction and
redemption or repurchase of outstanding securities until such needs can be
financed with long-term debt. In recent history, short-term funding needs have
been provided for by cash on hand and AEP’s commercial paper program. Funds are
made available to subsidiaries under the AEP corporate borrowing program.
Certain public utility subsidiaries of AEP also sell accounts receivable to
provide liquidity.
AEP’s
revolving credit agreements (which backstop the commercial paper program)
include covenants and events of default typical for this type of facility,
including a maximum debt/capital test and a $50 million cross-acceleration
provision. At December 31, 2006, AEP was in compliance with its debt covenants.
With the exception of a voluntary bankruptcy or insolvency, any event of default
has either or both a cure period or notice requirement before termination of
the
agreements. A voluntary bankruptcy or insolvency would be considered an
immediate termination event. See Management’s
Financial Discussion and Analysis of Results of Operations,
included in the 2006 Annual Reports, under the heading entitled Financial
Condition for
additional information with respect to AEP’s credit agreements.
AEP’s
subsidiaries have also utilized, and expect to continue to utilize, additional
financing arrangements, such as leasing arrangements, including the leasing
of
coal transportation equipment and facilities.
Credit
Ratings
In
September 2005, Moody’s upgraded AEP’s senior unsecured rating to Baa2 from Baa3
and its commercial paper rating to Prime-2 from Prime-3. There were no changes
in the ratings or rating outlook for AEP or AEP’s rated subsidiaries by Moody’s
since that time. S&P did not change the ratings of AEP or its rated
subsidiaries during 2006; it did improve our business risk profile rating from
six to five. Fitch placed TNC on negative outlook in April 2006 but has made
no
other changes to the ratings of AEP or its rated subsidiaries during
2006.
See
Management’s
Financial Discussion and Analysis of Results of Operations,
included in the 2006 Annual Reports, under the heading entitled Financial
Condition for
additional information with respect to the credit ratings of the registrants
other than AEGCo.
ENVIRONMENTAL
AND OTHER MATTERS
General
AEP’s
subsidiaries are currently subject to regulation by federal, state and local
authorities with regard to air and water-quality control and other environmental
matters, and are subject to zoning and other regulation by local authorities.
The environmental issues that are potentially material to the AEP system
include:
In
addition to imposing continuing compliance obligations, these laws and
regulations authorize the imposition of substantial penalties for noncompliance,
including fines, injunctive relief and other sanctions. See Management’s
Financial Discussion and Analysis of Results of Operations
under
the heading entitled Environmental
Matters,
included in the 2006 Annual Reports, for
further information with respect to environmental issues.
If
our
expenditures for pollution control technologies, replacement generation and
associated operating costs are not recoverable from customers through regulated
rates (in regulated jurisdictions) or market prices (in deregulated
jurisdictions), those costs could adversely affect future results of operations
and cash flows, and possibly financial condition.
The
cost
of complying with applicable environmental laws, regulations and rules is
expected to be material to the AEP System.
See
Management’s
Financial Discussion and Analysis of Results of Operations under
the
heading entitled Environmental
Matters and
Note
6 to the consolidated financial statements entitled Commitments,
Guarantees and Contingencies, included
in the 2006 Annual Reports, for further information with respect to
environmental matters.
Environmental
Investments
Investments
related to improving AEP System plants’ environmental performance and compliance
with air and water quality standards during 2004, 2005 and 2006 and the current
estimates for 2007, 2008 and 2009 are shown below, in each case excluding AFUDC
or capitalized interest. Substantial investments in addition to the amounts
set
forth below are expected by the System in future years in connection with the
modification and addition of facilities at generating plants for environmental
quality controls in order to comply with air and water quality standards which
have been or may be adopted. Future investments could be significantly greater
if litigation regarding whether AEP properly installed emission control
equipment on its plants is resolved against any AEP subsidiaries or emissions
reduction requirements are accelerated or otherwise become more onerous or
if
CO2
becomes
regulated. See Management’s
Financial Discussion and Analysis of Results of Operations under
the
heading entitled Environmental
Matters
and Note
6 to
the consolidated financial statements, entitled Commitments,
Guarantees and Contingencies, included
in the 2006 Annual Reports, for more information regarding this litigation
and
environmental expenditures in general.
Figures
set forth in parentheses reflect amounts invested and later expensed as a result
of project cancellation or significant delay.
Electric
and Magnetic Fields
EMF
are
found everywhere there is electricity. Electric fields are created by the
presence of electric charges. Magnetic fields are produced by the flow of those
charges. This means that EMF are created by electricity flowing in transmission
and distribution lines, electrical equipment, household wiring, and
appliances.
A
number
of studies in the past several years have examined the possibility of adverse
health effects from EMF. While some of the epidemiological studies have
indicated some association between exposure to EMF and health effects, none
has
produced any conclusive evidence that EMF does or does not cause adverse health
effects.
Management
cannot predict the ultimate impact of the question of EMF exposure and adverse
health effects. If further research shows that EMF exposure contributes to
increased risk of cancer or other health problems, or if the courts conclude
that EMF exposure harms individuals and that utilities are liable for damages,
or if states limit the strength of magnetic fields to such a level that the
current electricity delivery system must be significantly changed, then the
results of operations and financial condition of AEP and its operating
subsidiaries could be materially adversely affected unless these costs can
be
recovered from customers.
UTILITY
OPERATIONS
GENERAL
Utility
operations constitute most of AEP’s business operations. Utility operations
include (i) the generation, transmission and distribution of electric power
to
retail customers and (ii) the supplying and marketing of electric power at
wholesale (through the electric generation function) to other electric utility
companies, municipalities and other market participants. AEPSC, as agent for
AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel
procurement and power-related risk management and trading
activities.
ELECTRIC
GENERATION
Facilities
AEP’s
public utility subsidiaries own or lease approximately 35,000 MW of domestic
generation. See Item
2 — Properties for
more
information regarding AEP’s generation capacity.
AEP
Power Pool and CSW Operating Agreement
APCo,
CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement
defining how they share the costs and benefits associated with their generating
plants. This sharing is based upon each company’s “member-load-ratio.” The
Interconnection Agreement has been approved by the FERC.
The
member-load-ratio is calculated monthly by dividing such company’s highest
monthly peak demand for the last twelve months by the aggregate of the highest
monthly peak demand for the last twelve months for all AEP East companies.
As of
December 31, 2006, the member-load-ratios were as follows:
The
Ohio
Act was enacted in 2001. To comply with that law CSPCo and OPCo functionally
separated their generation business from their remaining operations. They plan
to remain functionally separated through at least December 31, 2008 as
authorized by their rate stabilization plans approved by the PUCO. CSPCo and
OPCo have been involved in discussions with various stakeholders in Ohio about
potential legislation to address the period following the expiration of the
rate
stabilization plans. See Note 4 to the consolidated financial statements,
entitled Rate
Matters,
included in the 2006 Annual Reports, for more information.
Since
1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System
Interim Allowance Agreement (Allowance Agreement), which provides, among other
things, for the transfer of emission allowances associated with transactions
under the Interconnection Agreement.
The
following table shows the net (credits) or charges allocated among the parties
under the Interconnection Agreement during the years ended December 31, 2004,
2005 and 2006:
PSO,
SWEPCo, and AEPSC are parties to a Restated and Amended Operating Agreement
originally dated as of January 1, 1997 (CSW Operating Agreement), which has
been
approved by the FERC. The CSW Operating Agreement requires these public utility
subsidiaries to maintain adequate annual planning reserve margins and requires
the subsidiaries that have capacity in excess of the required margins to make
such capacity available for sale to other public utility subsidiary parties
as
capacity commitments. Parties are compensated for energy delivered to the
recipients based upon the deliverer’s incremental cost plus a portion of the
recipient’s savings realized by the purchaser that avoids the use of more costly
alternatives. Revenues and costs arising from third party sales in their region
are generally shared based on the amount of energy each west zone public utility
subsidiary contributes that is sold to third parties. The separation of the
generation business undertaken by TCC and TNC to comply with the Texas Act
has
made the business operations of TCC and TNC incompatible with the CSW Operating
Agreement. As a result, with FERC approval, these companies are no longer
parties to, and no longer supply generating capacity under, the CSW Operating
Agreement.
The
following table shows the net (credits) or charges allocated among the parties
under the CSW Operating Agreement during the years ended December 31, 2004,
2005
and 2006:
Power
generated by or allocated or provided under the Interconnection Agreement or
CSW
Operating Agreement to any public utility subsidiary is primarily sold to
customers by such public utility subsidiary at rates approved by the public
utility commission in the jurisdiction of sale. In Ohio and Virginia, such
rates
are based on a statutory formula as those jurisdictions continue to transition
to the use of market rates for generation. See Regulation
— Rates
under
Item
1, Utility Operations.
Under
both the Interconnection Agreement and CSW Operating Agreement, power that
is
not needed to serve the native load of our public utility subsidiaries is sold
in the wholesale market by AEPSC on behalf of those subsidiaries. See
Risk
Management and Trading,
below,
for
a
discussion of the trading and marketing of such power.
AEP’s
System Integration Agreement, which has been approved by the FERC, provides
for
the integration and coordination of AEP’s East companies, PSO and SWEPCO. This
includes joint dispatch of generation within the AEP System and the
distribution, between the two zones, of costs and benefits associated with
the
transfers of power between the two zones (including sales to third parties
and
risk management and trading activities). It is designed to function as an
umbrella agreement in addition to the Interconnection Agreement and the CSW
Operating Agreement, each of which controls the distribution of costs and
benefits for activities within each zone. The separation of the generation
business undertaken by TCC and TNC to comply with the Texas Act has also made
the business operations of TCC and TNC incompatible with the System Integration
Agreement. As a result, with FERC approval, these two companies have been
removed from this agreement.
Risk
Management and Trading
As
agent
for AEP’s public utility subsidiaries, AEPSC sells excess power into the market
and engages in power, natural gas, coal and emissions allowances risk management
and trading activities focused in regions in which AEP traditionally operates.
These activities primarily involve the purchase and sale of electricity (and
to
a lesser extent, natural gas, coal and emissions allowances) under physical
forward contracts at fixed and variable prices. These contracts include physical
transactions, over-the-counter swaps and exchange-traded futures and options.
The majority of physical forward contracts are typically settled by entering
into offsetting contracts. These
transactions are executed with numerous counterparties or on exchanges.
Counterparties and exchanges may require cash or cash related instruments to
be
deposited on these transactions as margin against open positions. As of December
31, 2006, counterparties and exchanges have posted approximately $156 million
in
cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s
public utility subsidiaries (while, as of that date, AEP’s public utility
subsidiaries had posted approximately $110 million with counterparties and
exchanges). Since open trading contracts are valued based on changes in market
power prices, exposures change daily.
Fuel
Supply
The
following table shows the sources of power generated by the AEP
System:
Variations
in the generation of nuclear power are primarily related to refueling and
maintenance outages in addition to the sale of TCC’s share of a nuclear
generating unit in May 2005. Variations in the generation of natural gas power
are primarily related to the availability of cheaper alternatives to fulfill
certain power requirements and the deactivation or sale of certain gas-fired
plants owned by TCC and TNC. Price increases in one or more fuel sources
relative to other fuels generally result in increased use of other
fuels.
Coal
and Lignite:
AEP’s
public utility subsidiaries procure coal and lignite under a combination of
purchasing arrangements including long-term contracts, affiliate operations,
short-term, and spot agreements with various producers and coal trading firms.
The price for most solid fuels generally has been increasing. Management has
responded to increases in the price of coal by rebalancing the coal used in
its
generating facilities with products from different coal regions and sources
that
have different heat and sulfur contents. This rebalancing is an ongoing process
that is expected to continue,
primarily enabled by the installation of scrubbers at many of our generating
facilities.
Management believes, but cannot provide assurances, that AEP’s public utility
subsidiaries will be able to secure and transport coal and lignite of adequate
quality and in adequate quantities to operate their coal and lignite-fired
units. Through
subsidiaries, AEP owns or leases more than 7,000 railcars, 600 barges, 15
towboats and a coal handling terminal with 20 million tons of annual capacity
to
move and store coal for use in its generating facilities. See MEMCO Operations
for a discussion of AEP’s for-profit coal and other dry-bulk commodity
transportation operations that are not part of AEP’s Utility Operations
segment.
The
following table shows the amount of coal and lignite delivered to the AEP System
during the past three years and the average delivered price of spot coal
purchased by System companies:
The
coal
supplies at AEP System plants vary from time to time depending on various
factors, including customers’ usage of electric power, space limitations, the
rate of consumption at particular plants, labor issues and weather conditions
which may interrupt deliveries. At December 31, 2006, the System’s coal
inventory was approximately 44 days of normal usage. This estimate assumes
that
the total supply would be utilized through the operation of plants that use
coal
most efficiently.
In
cases
of emergency or shortage, system companies have developed programs to conserve
coal supplies at their plants. Such programs have been filed and reviewed with
officials of federal and state agencies and, in some cases, the relevant state
regulatory agency has prescribed actions to be taken under specified
circumstances by System companies, subject to the jurisdiction of such
agency.
The
FERC
has adopted regulations relating, among other things, to the circumstances
under
which, in the event of fuel emergencies or shortages, it might order electric
utilities to generate and transmit electric power to other regions or systems
experiencing fuel shortages, and to ratemaking principles by which such electric
utilities would be compensated. In addition, the federal government is
authorized, under prescribed conditions, to reallocate coal and to require
the
transportation thereof, for the use at power plants or major fuel-burning
installations experiencing fuel shortages.
Natural
Gas:
Through
its public utility subsidiaries, AEP consumed over
104
billion
cubic
feet of natural gas during 2006 for generating power. A majority of the natural
gas-fired power plants are connected to at least two pipelines, which allows
greater access to competitive supplies and improves delivery reliability. A
portfolio of long-term, monthly, seasonal firm and daily peaking purchase and
transportation agreements (that are entered into on a competitive basis and
based on market prices) supplies natural gas requirements for each
plant.
Nuclear: I&M
has made commitments to meet the current nuclear fuel requirements of the Cook
Plant. I&M has made and will make purchases of uranium in various forms in
the spot, short-term, and mid-term markets until it decides that deliveries
under long-term supply contracts are warranted.
For
purposes of the storage of high-level radioactive waste in the form of spent
nuclear fuel, I&M completed modifications to its spent nuclear fuel storage
pool more than 10 years ago. I&M anticipates that the Cook Plant has
sufficient storage capacity for its spent nuclear fuel to permit normal
operations through 2013. I&M has initiated a project to study the use of dry
cask storage.
Nuclear
Waste and Decommissioning
As
the
owner of the Cook Plant, I&M has a significant future financial commitment
to dispose of spent nuclear fuel and decommission and decontaminate the plant
safely. The cost to decommission a nuclear plant is affected by NRC regulations
and the SNF disposal program. The estimated cost of decommissioning and disposal
of low-level radioactive waste for the Cook Plant ranges from $733 million
to
$1.3 billion in 2006 nondiscounted dollars. At December 31, 2006, the total
decommissioning trust fund balance for the Cook Plant was $974 million. The
ultimate cost of retiring the Cook Plant may be materially different from
estimates and funding targets as a result of the:
Accordingly,
management is unable to provide assurance that the ultimate cost of
decommissioning the Cook Plant will not be significantly different than current
projections.
See
Note
10 to the consolidated financial statements, entitled Nuclear,
included in the 2006 Annual Reports, for information with respect to nuclear
waste and decommissioning.
Low-Level
Radioactive Waste:
The
LLWPA
mandates that the responsibility for the disposal of low-level radioactive
waste
rests with the individual states. Low-level radioactive waste consists largely
of ordinary refuse and other items that have come in contact with radioactive
materials. Michigan does not currently have a disposal site for such waste
available. I&M cannot predict when such a site may be available, but South
Carolina and Utah operate low-level radioactive waste disposal sites and
currently accept low-level radioactive waste from Michigan. I&M’s access to
the South Carolina facility is currently allowed through the end of fiscal
year
2008. There is currently no set date limiting I&M’s access to the Utah
facility.
Structured
Arrangements Involving Capacity, Energy, and Ancillary
Services
In
January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement
relating to the construction and operation of a 510 MW gas-fired electric
generating peaking facility to be owned by NPC and called the Mone Plant. OPCo
is entitled to 100% of the power generated by the Mone Plant, and is responsible
for the fuel and other costs of the facility through May 2007, as extended.
Following that, NPC and OPCo will be entitled to 80% and 20%, respectively,
of
the power of the Mone Plant, and both parties will generally be responsible
for
their allocable portion of the fuel and other costs of the facility.
Certain
Power Agreements
AEGCo:
Since
its
formation in 1982, AEGCo’s business has consisted of the ownership and financing
of its 50% interest in Unit 1 of the Rockport Plant and, since 1989, its 50%
leasehold interest in Unit 2 of the Rockport Plant. Substantially all of the
operating revenues of AEGCo are derived from the sale of capacity and energy
associated with its interest in the Rockport Plant to I&M and KPCo pursuant
to unit power agreements, which have been approved by the FERC.
The
I&M Power Agreement provides for the sale by AEGCo to I&M of all the
capacity (and the energy associated therewith) available to AEGCo at the
Rockport Plant. Whether or not power is available from AEGCo, I&M is
obligated to pay as a demand charge for the right to receive such power (and
as
an energy charge for any associated energy taken by I&M). When added to
amounts received by AEGCo from any other sources, such amounts will be at least
sufficient to enable AEGCo to pay all its operating and other expenses,
including a rate of return on the common equity of AEGCo as approved by FERC,
currently 12.16%. The I&M Power Agreement will continue in effect until the
last of the lease terms of Unit 2 of the Rockport Plant has expired (currently
December 2022) unless extended in specified circumstances.
Pursuant
to an assignment between I&M and KPCo, and a unit power agreement between
KPCo and AEGCo, AEGCo sells KPCo 30% of the capacity (and the energy associated
therewith) available to AEGCo from both units of the Rockport Plant. KPCo has
agreed to pay to AEGCo the amounts which I&M would have paid AEGCo under the
terms of the I&M Power Agreement for such entitlement. The KPCo unit power
agreement expires in December 2022.
AEGCo
and
AEP have entered into a capital funds agreement pursuant to which, among other
things, AEP has unconditionally agreed to make cash capital contributions,
or in
certain circumstances subordinated loans, to AEGCo to the extent necessary
to
enable AEGCo to (i) maintain such an equity component of capitalization as
required by governmental regulatory authorities; (ii) provide its proportionate
share of the funds required to permit commercial operation of the Rockport
Plant; (iii) enable AEGCo to perform all of its obligations, covenants and
agreements under, among other things, all loan agreements, leases and related
documents to which AEGCo is or becomes a party (AEGCo Agreements); and (iv)
pay
all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations)
under
the AEGCo Agreements, other than indebtedness, obligations or liabilities owing
to AEP. The capital funds agreement will terminate after all AEGCo obligations
have been paid in full.
OVEC: AEP
and
several unaffiliated utility companies jointly own OVEC. The aggregate equity
participation of AEP in OVEC is 43.47%. Until September 1, 2001, OVEC supplied
from its generating capacity the power requirements of a uranium enrichment
plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are
now
entitled to receive and obligated to pay for all OVEC capacity (approximately
2,200 MW) in proportion to their respective power participation ratios. The
aggregate power participation ratio of APCo, CSPCo, I&M and OPCo is 43.47%.
The proceeds from the sale of power by OVEC are designed to be sufficient for
OVEC to meet its operating expenses and fixed costs and to provide a return
on
its equity capital. The Amended and Restated Inter-Company Power Agreement,
which defines the rights of the owners and sets the power participation ratio
of
each, will expire by its terms on March 12, 2026. AEP and the other owners
have
been evaluating the need for environmental investments related to their
ownership interests, which are material. In December 2006, OVEC’s Board of
Directors authorized interim capital expenditures totaling $366 million in
order
to complete detailed engineering and begin construction of flue gas
desulfurization (sulfur dioxide scrubber) projects and the associated scrubber
waste disposal landfills. If approved, the estimated total cost to complete
the
projects would be slightly in excess of $1 billion, which OVEC would expect
to
finance through issuing debt. With the expiration of that provision,
Buckeye is entitled to receive and must pay for power up to its proportionate
share of the station.
Buckeye:
On
October 1, 2004, AEP joined PJM, and the Buckeye transmission service over
the
AEP System was transferred under the PJM Open Access Transmission Tariff (OATT).
The Cardinal Station Agreement between OPCO and Buckeye contains a provision
that expired in May 2006. Under that provision, Buckeye was entitled to receive,
and was obligated to pay for, the excess of its maximum one-hour coincident
peak
demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of
the
generating units which Buckeye currently owns in the Cardinal Station. Such
demand, which occurred on July 25, 2005, was recorded at 1,434,807
kilowatts. With
the
expiration of that provision, Buckeye is entitled to receive and must pay for
power in amounts equal to its proportionate share of the
station.
ELECTRIC
TRANSMISSION AND DISTRIBUTION
General
AEP’s
public utility subsidiaries (other than AEGCo) own and operate transmission
and
distribution lines and other facilities to deliver electric power. See
Item
2—Properties for
more
information regarding the transmission and distribution lines. Most of the
transmission and distribution services are sold, in combination with electric
power, to retail customers of AEP’s public utility subsidiaries in their service
territories. These sales are made at rates established and approved by the
state
utility commissions of the states in which they operate, and in some instances,
approved by the FERC. See Regulation—Rates.
The
FERC regulates and approves the rates for wholesale transmission transactions.
See Item
1 - Business/Utility Operations - Regulation—FERC.
As
discussed below, some transmission services also are separately sold to
non-affiliated companies.
AEP’s
public utility subsidiaries (other than AEGCo) hold franchises or other rights
to provide electric service in various municipalities and regions in their
service areas. In some cases, these franchises provide the utility with the
exclusive right to provide electric service. These franchises have varying
provisions and expiration dates. In general, the operating companies consider
their franchises to be adequate for the conduct of their business. For a
discussion of competition in the sale of power, see Item
1 - Business/Utility Operations - Competition.
AEP
Transmission Pool
Transmission
Equalization Agreement: APCo,
CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single
interconnected and coordinated system and are parties to the TEA, defining
how
they share the costs and benefits associated with their relative ownership
of
the extra-high-voltage transmission system (facilities rated 345kV and above)
and certain facilities operated at lower voltages (138kV up to 345kV). The
TEA
has been approved by the FERC. Sharing under the TEA is based upon each
company’s “member-load-ratio.” The member-load-ratio is calculated monthly by
dividing such company’s highest monthly peak demand for the last twelve months
by the aggregate of the highest monthly peak demand for the last twelve months
for all east zone operating companies. The respective peak demands and
member-load-ratios as of December 31, 2006 are set forth above in the section
titled ELECTRIC GENERATION - AEP Power Pool and CSW Operating
Agreement.
The
following table shows the net (credits) or charges allocated among the parties
to the TEA during the years ended December 31, 2004, 2005 and 2006:
Transmission
Coordination Agreement: PSO,
SWEPCo, TCC, TNC and AEPSC are parties to the TCA. The TCA has been approved
by
the FERC and establishes a coordinating committee, which is charged with the
responsibility of (i) overseeing the coordinated planning of the transmission
facilities of the AEP West companies, including the performance of transmission
planning studies, (ii) the interaction of such subsidiaries with independent
system operators and other regional bodies interested in transmission planning
and (iii) compliance with the terms of the OATT filed with the FERC and the
rules of the FERC relating to such tariff.
Under
the
TCA, the AEP West companies have delegated to AEPSC the responsibility of
monitoring the reliability of their transmission systems and administering
the
AEP OATT on their behalf. Prior to September 2005, the TCA also provided for
the
allocation among the AEP West companies of revenues collected for transmission
and ancillary services provided under the AEP OATT. Since then, these
allocations have been determined by the FERC-approved OATT for the SPP (with
respect to PSO and SWEPCo) and PUCT-approved protocols for ERCOT (with respect
to TCC and TNC).
The
following table shows the net (credits) or charges allocated among the parties
to the TCA prior to September 2005, and pursuant to the SPP OATT and ERCOT
protocols as described above during the years ended December 31, 2004, 2005
and
2006:
Transmission
Services for Non-Affiliates: In
addition to providing transmission services in connection with their own power
sales, AEP’s public utility subsidiaries through RTOs also provide transmission
services for non-affiliated companies. See Item
1 - Business/Utility operations - Regional Transmission Organizations,
below.
Transmission
of electric power by AEP’s public utility subsidiaries is regulated by the FERC.
Coordination
of East and West Zone Transmission: AEP’s
System Transmission Integration Agreement provides for the integration and
coordination of the planning, operation and maintenance of the transmission
facilities of AEP East and AEP West companies. The System Transmission
Integration Agreement functions as an umbrella agreement in addition to the
TEA
and the TCA. The System Transmission Integration Agreement contains two service
schedules that govern:
The
System Transmission Integration Agreement contemplates that additional service
schedules may be added as circumstances warrant.
Regional
Transmission Organizations
On
April
24, 1996, the FERC issued orders 888 and 889. These orders require each public
utility that owns or controls interstate transmission facilities to file an
open
access network and point-to-point transmission tariff that offers services
comparable to the utility’s own uses of its transmission system. The orders also
require utilities to functionally unbundle their services, by requiring them
to
use their own tariffs in making off-system and third-party sales. As part of
the
orders, the FERC issued a pro-forma
tariff
that reflects the Commission’s views on the minimum non-price terms and
conditions for non-discriminatory transmission service. In addition, the orders
require all transmitting utilities to establish an OASIS, which electronically
posts transmission information such as available capacity and prices, and
require utilities to comply with Standards of Conduct that prohibit utilities’
system operators from providing non-public transmission information to the
utility’s merchant energy employees. The orders also allow a utility to seek
recovery of certain prudently incurred stranded costs that result from unbundled
transmission service.
In
December 1999, FERC issued Order 2000, which provides for the voluntary
formation of RTOs, entities created to operate, plan and control utility
transmission assets. Order 2000 also prescribes certain characteristics and
functions of acceptable RTO proposals. As a condition of FERC’s approval in 2000
of AEP’s merger with CSW, AEP was required to transfer functional control of its
transmission facilities to one or more RTOs. The AEP East Companies integrated
into PJM (a FERC-approved RTO) on October 1, 2004.
SWEPCo
and PSO are members of the SPP. In February 2004, the FERC conditionally
approved SPP as an RTO. In October 2004, the FERC issued an order granting
RTO
status to SPP subject to certain filings. The APSC and LPSC have
ordered the utilities in those states, including our utilities, to analyze
and
submit to them the costs and benefits of RTO options available to the utilities.
Certain states in the region have undertaken and released a study investigating
the costs and benefits of SPP developing into a RTO that administers energy
and
associated markets. On August 10, 2006, the APSC issued an order approving,
among other things, SWEPCo’s participation in SPP, subject to certain reporting
and continuing oversight conditions.
The
remaining AEP West companies (TCC and TNC) are members of ERCOT.
See
Note
4 to the consolidated financial statements, entitled Rate
Matters,
included in the 2006 Annual Reports under the heading entitled RTO
Formation/Integration Costs and
Transmission Rate Proceedings at the FERC
for a
discussion of public utility subsidiary participation in RTOs.
REGULATION
General
Except
for retail generation sales in Ohio, Virginia and the ERCOT area of Texas,
AEP’s
public utility subsidiaries’ retail rates and certain other matters are subject
to traditional regulation by the state utility commissions. While still
regulated, retail sales in Michigan are now made at unbundled rates. See
Item
1 - Utility Operations - Electric Restructuring and Customer Choice Legislation
and
Rates,
below.
AEP’s subsidiaries are also subject to regulation by the FERC under the FPA.
I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954,
as amended, with respect to the operation of the Cook Plant. AEP and its public
utility subsidiaries are also subject to the regulatory provisions of EPACT,
much of which is administered by the FERC. EPACT contains key provisions
affecting the electric power industry such as giving the FERC “backstop”
transmission siting authority as well as increased utility merger oversight.
The
law also provides incentives and funding for clean coal technologies and
initiatives to voluntarily reduce greenhouse gases.
Rates
Historically,
state utility commissions have established electric service rates on a
cost-of-service basis, which is designed to allow a utility an opportunity
to
recover its cost of providing service and to earn a reasonable return on its
investment used in providing that service. A utility’s cost of service generally
reflects its operating expenses, including operation and maintenance expense,
depreciation expense and taxes. State utility commissions periodically adjust
rates pursuant to a review of (i) a utility’s revenues and expenses during a
defined test period and (ii) such utility’s level of investment. Absent a legal
limitation, such as a law limiting the frequency of rate changes or capping
rates for a period of time as part of a transition to customer choice of
generation suppliers, a state utility commission can review and change rates
on
its own initiative. Some states may initiate reviews at the request of a
utility, customer, governmental or other representative of a group of customers.
Such parties may, however, agree with one another not to request reviews of
or
changes to rates for a specified period of time.
In
many
jurisdictions, the rates of AEP’s public utility subsidiaries are generally
based on the cost of providing traditional bundled electric service (i.e.,
generation, transmission and distribution service). In the ERCOT area of Texas,
our utilities have exited the generation business and they currently charge
unbundled cost-based rates for transmission and distribution service. In Ohio,
rates are transitioning from bundled cost-based rates for electric service
to
unbundled cost-based rates for transmission and distribution service on the
one
hand, and market pricing for and/or customer choice of generation on the other.
Historically, the state regulatory frameworks in the service area of the AEP
System reflected specified fuel costs as part of bundled (or, more recently,
unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates
and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost
recovery from customers and therefore provide protection against exposure to
fuel cost changes. While the historical framework remains in a portion of AEP’s
service territory, recovery of increased fuel costs through a fuel adjustment
clause is no longer provided for in Ohio.
The
following state-by-state analysis summarizes the regulatory environment of
certain major jurisdictions in which AEP operates. Several public utility
subsidiaries operate in more than one jurisdiction.
Indiana:
I&M
provides retail electric service in Indiana at bundled rates approved by the
IURC. While rates are set on a cost-of-service basis, I&M’s base rates are
capped through June 30, 2007. Its fuel recovery rate is capped through that
time
period at a level that automatically increased in January 2006 and January
2007.
I&M expects, however, that its actual fuel costs will exceed the capped fuel
rates permitted through June 30, 2007.
Ohio:
CSPCo
and
OPCo each operated as a functionally separated utility and provided “default”
retail electric service to customers at unbundled rates pursuant to the Ohio
Act
through December 31, 2006. The PUCO approved the rate stabilization plans filed
by CSPCo and OPCo (which, among other things, address default retail generation
service rates from January 1, 2006 through December 31, 2008). The
Ohio
Supreme Court vacated and remanded
the
PUCO’s approval of the rate stabilization plans. In response, the PUCO issued an
order requiring CSPCo and OPCo to make additional filings and holding that
their
rate stabilization plans remained in effect. CSPCo and OPCo have submitted
proposals with the PUCO addressing the matters identified by the PUCO. Retail
generation rates will be determined consistent with the rate stabilization
plan
until December 31, 2008. CSPCo and OPCo are providing and will continue to
provide distribution services to retail customers at rates approved by the
PUCO.
These rates will be frozen (with certain exceptions, including automatic annual
increases in generation rates of 3% and 7% for CSPCo and OPCo, respectively)
from their levels as of December 31, 2005 through December 31, 2008.
Transmission services will continue to be provided at rates established by
the
FERC. CSPCo and OPCo have been involved in discussions with various stakeholders
in Ohio about potential legislation to address the period following the
expiration of the rate stabilization plans. See Note 4 to the consolidated
financial statements, entitled Rate
Matters,
included in the 2006 Annual Reports, for more information.
Oklahoma:
PSO
provides retail electric service in Oklahoma at bundled rates approved by the
OCC. PSO’s rates are set on a cost-of-service basis. Fuel and purchased energy
costs above the amount included in base rates are recovered by applying a fuel
adjustment factor to retail kilowatt-hour sales. The factor is generally
adjusted annually and is based upon forecasted fuel and purchased energy costs.
Over or under collections of fuel costs for prior periods are returned to or
recovered from customers when new annual factors are established. In November
2006, PSO filed a request with the OCC seeking an increase in base rates and
other rate relief. The OCC has not yet ruled on this filing. See Note 4 to
the
consolidated financial statements, entitled Rate
Matters,
included in the 2006 Annual Reports, for information regarding current rate
proceedings.
Texas: TCC
has
sold all of its generation assets and TNC has transferred its active generation
capacity to a non-utility affiliate pursuant to a 20-year agreement. TCC and
TNC
serve most of their retail customers in the ERCOT area of Texas through
non-affiliated REPs. TCC and TNC provide retail transmission and distribution
service on a cost-of-service basis at rates approved by the PUCT and wholesale
transmission service under tariffs approved by the FERC consistent with PUCT
rules. In November 2006, TCC and TNC filed requests with the PUCT seeking
increases in the rates charged to REPs for delivering electricity over their
transmission and distribution lines. The PUCT has not ruled on the filings.
See
Note 4 to the consolidated financial statements, entitled Rate
Matters included
in the 2006 Annual Reports, for information on current rate proceedings. In
August 2006, the PUCT delayed competition in the SPP area of Texas until at
least January 1, 2011. As such, SWEPCo’s Texas operations continue to operate
and to be regulated as a traditional bundled utility with both base and fuel
rates.
Virginia: APCo
provides retail electric service in Virginia at unbundled rates. In February
2007, the Virginia legislature adopted amendments to its previously-enacted
electric restructuring law. The amendments would cut two years off of the
transition period (from 2010 to 2008) after which rates for retail generation
supply would return to a form of cost-based regulation. The Governor of Virginia
has not yet signed this legislation. APCo’s unbundled generation, transmission
(which reflect FERC-approved transmission rates) and distribution rates, as
well
as its functional separation plan, were approved by the VSCC in December 2001.
APCO’s base rates are capped at their mid-1999 levels until the end of the
transition period (now December 31, 2010), or sooner if the VSCC finds that
a
competitive market for generation exists in Virginia, but APCo is permitted
to
seek two changes to its capped rates through December 31, 2010. In addition,
APCo is entitled to annual rate changes to recover the incremental costs it
incurs for transmission and distribution reliability and compliance with state
or federal environmental laws or regulations. In May 2006, APCo filed a request
with the VSCC seeking an increase in base rates. Hearings on this request were
held in December 2006. APCo expects a ruling in 2007. APCo is entitled to
adjustments to fuel rates through 2010 to recover its actual fuel costs, the
fuel component of its purchased power costs and certain capacity charges. APCo
recovers its generation capacity charges through capped base rates. In November
2006, the VSCC approved APCo’s previous request to recover additional
environmental and reliability-related costs. See Note 4 to the consolidated
financial statements, entitled Rate
Matters,
included in the 2006 Annual Reports, for additional information on these
matters.
West
Virginia:
APCo
and
WPCo provide retail electric service at bundled rates approved by the WVPSC.
West Virginia generally allows for timely recovery of fuel costs. In July 2006,
the WVPSC approved an increase in the retail rates of APCo and WPCo and the
reactivation of their suspended operative fuel clause and other recovery
mechanisms. See Note 4 to the consolidated financial statements, entitled
Rate
Matters,
included in the 2006 Annual Reports, for additional information on current
rate
proceedings.
Other
Jurisdictions:
The
public utility subsidiaries of AEP also provide service at regulated bundled
rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled
rates in Michigan.
The
following table illustrates the current rate regulation status of the states
in
which the public utility subsidiaries of AEP operate:
FERC
Under
the
FPA, FERC regulates rates for interstate sales at wholesale, transmission of
electric power, accounting and other matters, including construction and
operation of hydroelectric projects. FERC regulations require AEP to provide
open access transmission service at FERC-approved rates. FERC also regulates
unbundled transmission service to retail customers. FERC also regulates the
sale
of power for resale in interstate commerce by (i) approving contracts for
wholesale sales to municipal and cooperative utilities and (ii) granting
authority to public utilities to sell power at wholesale at market-based rates
upon a showing that the seller lacks the ability to improperly influence market
prices. Except for wholesale power that AEP delivers within its control area
of
the SPP, AEP has market-rate authority from FERC, under which much of its
wholesale marketing activity takes place.
The
FERC
has jurisdiction over the issuances of securities of our public utility
subsidiaries, the acquisition of securities of utilities, the acquisition or
sale of certain utility assets, and mergers with another electric utility or
holding company. In addition, both FERC and state regulators are permitted
to
review the books and records of any company within a holding company system.
EPACT gives the FERC “backstop” transmission siting authority as well as
increased utility merger oversight.
ELECTRIC
RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION
Certain
states in AEP’s service area have adopted restructuring or customer choice
legislation. In general, this legislation provides for a transition from bundled
cost-based rate regulated electric service to unbundled cost-based rates for
transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier. At a minimum, this legislation
allows retail customers to select alternative generation suppliers. Electric
restructuring and/or customer choice began on January 1, 2001 in Ohio and on
January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric
restructuring in the SPP area of Texas has been delayed by the PUCT until at
least 2011. AEP’s public utility subsidiaries operate in both the ERCOT and SPP
areas of Texas. See Note 4 to the consolidated financial statements entitled
Rate
Matters for
additional information.
Ohio
Restructuring
The
Ohio
Act requires vertically integrated electric utility companies that are in the
business of providing competitive retail electric service in Ohio to separate
their generating functions from their transmission and distribution functions.
Following the market development period (which ended December 31, 2005), retail
customers receive distribution and, where applicable, transmission service
from
the incumbent utility whose distribution rates are approved by the PUCO and
whose transmission rates are based on rates established by the FERC. The PUCO
approved CSPCo’s and OPCo’s rate stabilization plans that, among other things,
addressed default generation service rates from January 1, 2006 through December
31, 2008. See Item
1 - Utility Operations - Regulation—FERC for
a
discussion of FERC regulation of transmission rates, Regulation—Rates—Ohio
and
Note
4 to the consolidated financial statements entitled
Rate
Matters,
included in the 2006 Annual Reports,
for
a
discussion of the impact of restructuring on distribution rates. The PUCO
authorized CSPCo and OPCo to remain functionally separated through the end
of
that three-year period. The Supreme Court of Ohio vacated and remanded the
PUCO’s order authorizing the rate stabilization plans. In response, the PUCO
issued an order in August 2006 requiring CSPCo and OPCo to make additional
filings and holding that the rate stabilization plans remained in effect. CSPCo
and OPCo have submitted proposals with the PUCO addressing the matters
identified by the PUCO. CSPCo and OPCo have been involved in discussions with
various stakeholders in Ohio about potential legislation to address the period
following the expiration of the rate stabilization plans.
Texas
Restructuring
Signed
into law in June of 1999, the Texas Act substantially amended the regulatory
structure governing electric utilities in Texas in order to allow retail
electric competition for customers. Among other things, the Texas
Act:
The
Texas
Act provides each affected utility an opportunity to recover its generation
related regulatory assets and stranded costs resulting from the legal separation
of the transmission and distribution utility from the generation facilities
and
the related introduction of retail electric competition. Regulatory assets
consist of the Texas jurisdictional amount of generation-related regulatory
assets and liabilities in the audited financial statements as of December 31,
1998. Stranded costs consist of the positive excess of the net regulated book
value of generation assets (as of December 31, 2001) over the market value
of
those assets, taking specified factors into account, as ultimately determined
in
a PUCT true-up proceeding.
In
May
2005, TCC filed its stranded cost quantification application, or true-up
proceeding,
with the
PUCT seeking recovery of $2.4 billion of net stranded generation costs and
other
recoverable true-up items. A final order was issued in April 2006. In the final
order, the PUCT determined TCC’s net stranded generation costs and other
recoverable true-up items to be approximately $1.475 billion. Other parties
have
appealed the PUCT’s final order as unwarranted or too large; TCC has appealed
seeking additional recovery consistent with the Texas Act and related rules.
In
a preliminary ruling filed in February 2007, the Texas state district court
adjudicating the appeal of the final order in the true-up proceeding found
that
the PUCT erred in several respects, including the method used to determine
stranded costs and the awarding of certain carrying costs. Following the
preliminary ruling, the court granted a rehearing of the issue regarding the
method to determine stranded costs. That rehearing is scheduled for late March
2007. TCC intends to appeal any final adverse rulings regarding the PUCT’s order
in the true-up proceedings.
After
PUCT approval, in October 2006 TCC issued $1.74 billion of securitization bonds,
including additional issuance and carrying costs through the date of issuance.
The PUCT authorized negative competition transition charges in the amount of
$356 million in October 2006. TCC is required to refund this amount to its
ratepayers. For
a
discussion of (i) regulatory assets and stranded costs subject to recovery
by
TCC and (ii) rate adjustments made after implementation of restructuring to
allow recovery of certain costs by or with respect to TCC and TNC, see Note
4 to
the consolidated financial statements entitled Rate
Matters
included
in the 2006 Annual Reports.
Michigan
Customer Choice
Customer
choice commenced for I&M’s Michigan customers on January 1, 2002. Rates for
retail electric service for I&M’s Michigan customers were unbundled (though
they continue to be regulated) to allow customers the ability to evaluate the
cost of generation service for comparison with other suppliers. At December
31,
2006, none of I&M’s Michigan customers have elected to change suppliers and
no alternative electric suppliers are registered to compete in I&M’s
Michigan service territory.
Virginia
Restructuring
In
April
2004, the Governor of Virginia signed legislation that extends the transition
period for electricity restructuring, including capped rates, through December
31, 2010. The legislation provides specified cost recovery opportunities during
the capped rate period, including two optional general base rate changes and
an
opportunity for timely recovery, through a separate rate mechanism, of certain
incremental environmental and reliability costs incurred on and after July
1,
2004. In
February 2007, the Virginia legislature adopted amendments to its
previously-enacted electric restructuring law. The amendments would cut two
years off of the transition period (from 2010 to 2008) after which rates for
retail generation supply would return to a form of cost-based regulation. The
Governor of Virginia has not yet signed this legislation.
COMPETITION
The
public utility subsidiaries of AEP, like the electric industry generally, face
competition in the sale of available power on a wholesale basis, primarily
to
other public utilities and power marketers. The Energy Policy Act of 1992 was
designed, among other things, to foster competition in the wholesale market
by
creating a generation market with fewer barriers to entry and mandating that
all
generators have equal access to transmission services. As a result, there are
more generators able to participate in this market. The principal factors in
competing for wholesale sales are price (including fuel costs), availability
of
capacity and power and reliability of service.
AEP’s
public utility subsidiaries also compete with self-generation and with
distributors of other energy sources, such as natural gas, fuel oil and coal,
within their service areas. The primary factors in such competition are price,
reliability of service and the capability of customers to utilize sources of
energy other than electric power. With respect to competing generators and
self-generation, the public utility subsidiaries of AEP believe that they
generally maintain a favorable competitive position. With respect to alternative
sources of energy, the public utility subsidiaries of AEP believe that the
reliability of their service and the limited ability of customers to substitute
other cost-effective sources for electric power place them in a favorable
competitive position, even though their prices may be higher than the costs
of
some other sources of energy.
Significant
changes in the global economy in recent years have led to increased price
competition for industrial customers in the United States, including those
served by the AEP System. Some of these industrial customers have requested
price reductions from their suppliers of electric power. In addition, industrial
customers that are downsizing or reorganizing often close a facility based
upon
its costs, which may include, among other things, the cost of electric power.
The public utility subsidiaries of AEP cooperate with such customers to meet
their business needs through, for example, providing various off-peak or
interruptible supply options pursuant to tariffs filed with the various state
commissions. Occasionally, these rates are first negotiated, and then filed
with
the state commissions. The public utility subsidiaries of AEP believe that
they
are unlikely to be materially adversely affected by this
competition.
SEASONALITY
The
sale
of electric power is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this fluctuation may change due to the nature and location of
AEP’s facilities and the terms of power sale contracts into which AEP enters. In
addition, AEP has historically sold less power, and consequently earned less
income, when weather conditions are milder. Unusually mild weather in the future
could diminish AEP’s results of operations and may impact its financial
condition. Conversely, unusually extreme weather conditions could increase
AEP’s
results of operations.
MEMCO
OPERATIONS
Our
MEMCO
business segment transports coal and dry bulk commodities primarily on the
Ohio,
Illinois, and Lower Mississippi rivers. Almost all of our customers are
nonaffiliated third parties who obtain the transport coal and dry bulk
commodities for various uses. We charge these customers market rates for the
purpose of making a profit. Depending on market conditions and other factors,
including barge availability, we have also served AEP utility subsidiary
affiliates. Our affiliated utility customers procure the transport of coal
for
use as fuel in their respective generating plants. We charge affiliated
customers rates that reflect our costs. The MEMCO operations include
approximately 2,038 barges, 37 towboats and 10 harbor boats that we own or
lease.
Competition
within the barging industry for major commodity contracts is intense, with
a
number of companies offering transportation services in the waterways we serve.
We compete with other carriers primarily on the basis of commodity shipping
rates, but also with respect to customer
service, available routes, value-added services (including scheduling
convenience and flexibility), information timeliness and equipment. Since
1980, the industry has experienced consolidation. The resulting companies
increasingly offer the widespread geographic reach necessary to support major
national customers. Demand for barging services can be seasonal, particularly
with respect to the movement of harvested agricultural commodities (beginning
in
the late summer and extending through the fall.) Cold winter weather may also
limit our operations when certain of the waterways we serve are
closed.
Our
transportation operations are subject to regulation by the U.S. Coast
Guard, federal laws, state laws and certain international conventions.
Legislation has been proposed that could make our towboats subject to inspection
by the U.S. Coast Guard.
GENERATION
AND MARKETING
Our
generation and marketing business segment consists of non-utility generating
assets and as of January 2007, a competitive power supply and energy trading
business. We enter into short and long-term transactions to buy or sell
capacity, energy, and ancillary services primarily in the ERCOT market. The
assets utilized in this segment include approximately 791 MW of domestic wind
power and gas-fired generation facilities (of which AEP ownership is
approximately 551 MW) and, since January 2007, 377 MW of coal-fired capacity
obtained from TNC’s interest in the Oklaunion power station. TNC has entered
into a 20-year power agreement transferring this generating capacity to a
non-utility affiliate that we operate in order to comply with the separation
requirements of the Texas Act. The power obtained from the Oklaunion power
station is to be marketed and sold in ERCOT. We are regulated by the PUCT for
transactions inside ERCOT and by the FERC for transactions outside of ERCOT.
While peak load in ERCOT typically occurs in the summer, we do not necessarily
expect seasonal variation in our operations.
OTHER
Gas
Operations
In
January 2005, we sold a 98% controlling interest in HPL and related assets
with
the remaining 2% interest being sold to the buyer in November 2005. See Note
8
to the consolidated financial statements entitled Acquisitions,
Dispositions, Discontinued Operations, Impairments, and Assets Held for
Sale,
included in the 2006 Annual Reports for more information. As a result,
management anticipates that our gas marketing operations will be limited to
managing our obligations with respect to the gas transactions entered into
before these sales.
Plaquemine
Cogeneration Facility
Pursuant
to an agreement with Dow, AEP constructed an 880 MW cogeneration facility
(“Facility”)
at
Dow’s
chemical facility in Plaquemine, Louisiana that achieved commercial operation
status in 2004. Dow
used
a portion of the energy produced by the Facility and sold the excess power
to
us. We agreed to sell up to all of the excess 800 MW to Tractebel.
That power agreement is currently being litigated. See Note 6 to the
consolidated financial statements entitled Commitments,
Guarantees and Contingencies.
In
November 2006, we sold our interest in the Facility to Dow. Negotiations for
the
sale resulted in an after-tax impairment of approximately $136 million. See
Note
8 to the consolidated financial statements entitled Acquisitions,
Dispositions, Discontinued Operations, Impairments and Assets Held for Sale.
For
information regarding other non-core investments, see Note 8 to the consolidated
financial statements entitled Acquisitions,
Dispositions, Discontinued Operations, Impairments and Assets Held for Sale,
included
in the 2006 Annual Reports.
ITEM
1A. RISK
FACTORS
General
Risks of Our Regulated Operations
We
may not be able to recover the costs of our substantial planned investment
in
capital improvements and additions. (Applies
to each registrant.)
Our
business plan calls for extensive investment in capital improvements and
additions, including the installation of environmental upgrades and retrofits,
construction and/or acquisition of additional generation units and transmission
facilities, modernizing existing infrastructure as well as other initiatives.
Our public utility subsidiaries currently provide service at rates approved
by
one or more regulatory commissions. If these regulatory commissions do not
approve adjustments to the rates we charge, we would not be able to recover
the
costs associated with our planned extensive investment. This would cause our
financial results to be diminished. While we may seek to limit the impact of
any
denied recovery by attempting to reduce the scope of our capital investment,
there can be no assurance as to the effectiveness of any such mitigation
efforts, particularly with respect to previously incurred costs and
commitments.
Our
planned capital investment program coincides with a material increase in the
price of the fuels used to generate electricity. Many of our jurisdictions
have
fuel clauses that permit us to recover these increased fuel costs through rates
without a general rate case. While prudent capital investment and variable
fuel
costs each generally warrant recovery, in practical terms our regulators could
limit the amount or timing of increased costs that we would recover through
higher rates. Any such limitation could cause our financial results to be
diminished.
Our
request for rate recovery of additional costs may not be approved in
Virginia. (Applies
to AEP and APCo.)
APCo
filed a request with the VSCC in May 2006 seeking a net increase in base rates
of $198 million to recover increasing costs, including a return on equity of
11.5%. APCo also requested to apply its off-system sales margins (currently
credited to customers through base rates) to the fuel factor where they can
be
adjusted annually. APCo also requested to retain a portion of the off-system
sales margins. In May 2006, the VSCC issued an order placing the net requested
base rate increase into effect as of October 2, 2006, subject to refund. In
October 2006, the VSCC staff filed direct testimony recommending a base rate
increase of $13 million with a return on equity of 9.9% and no off-system sales
margin sharing. Other intervenors have recommended base rate increases ranging
from $42 million to $112 million. APCo has filed rebuttal testimony and hearings
were held in December 2006. If the VSCC denies the
requested rate recovery, it could adversely impact future results of operations
and cash flows.
Our
request for rate recovery of additional costs may not be approved in
Texas. (Applies
to AEP, TCC and TNC.)
TCC
and
TNC have filed requests with the PUCT to increase their transmission and
distribution rates. The rate requests include the amounts charged for the
delivery of electricity over TCC´s and TNC´s transmission and distribution
lines. TCC is seeking approval of an $81 million increase, which includes the
expiration of $20 million in billing credits that the PUCT required in approving
the merger of CSW into AEP. The credits have been in place since 2000. TNC
is
seeking approval of a $25 million increase, which includes the expiration of
$6.2 million in billing credits. TCC and TNC are requesting a return on equity
of 11.25% with a capital structure of approximately 60% debt/40% equity. If
the
PUCT denies the
requested rate recovery, it could adversely impact future results of operations
and cash flows.
Our
request for rate recovery of additional costs may not be approved in
Oklahoma. (Applies
to AEP and PSO.)
PSO
filed
a request with the OCC in November, 2006 seeking approval of a $50 million
overall increase in base rates, an annually adjusted rate mechanism to recover
the expected significant investment PSO will be making in new facilities,
several new and restructured tariffs to allow PSO to begin to reduce the
relationship between its revenues and its sales volumes, and to implement some
demand side management tariffs. PSO´s planned investments over the next five
years include new generation facilities ($1.12 billion), new and refurbished
transmission substations and lines ($302 million) and new distribution lines
and
equipment ($582 million). If the OCC denies the
requested rate recovery, it could adversely impact future results of operations
and cash flows.
We
may not be able to recover all of our fuel costs in Indiana.
(Applies
to AEP and I&M.)
I&M
entered into a settlement agreement which the IURC approved
in 2005. The
approved settlement caps fuel rates through June 2007 at increasing rates during
agreed-upon intervals. I&M has experienced a cumulative under-recovery of
fuel costs through December 2006. If future fuel costs through June 30, 2007
continue to exceed the agreed-upon caps, future results of operations and cash
flows would be adversely affected.
The
rates that SWEPCo may charge its customers may be reduced.
(Applies to SWEPCo.)
At
the
time of the CSW merger, SWEPCO agreed to file with the LPSC detailed financial
information typically utilized in a revenue requirement filing on a periodic
basis in order to demonstrate the lack of adverse impact from the merger. The
first such filing was in October 2002 and the second was in April 2004. Both
filings indicated SWEPCo’s rates should not be reduced. In April 2006, the LPSC
and SWEPCo agreed to update the financial information based on a 2005 test
year.
SWEPCo filed financial review schedules in May 2006 showing a return on equity
of 9.44% compared to the previously authorized return on equity of 11.1%. In
July 2006, consultants to the LPSC staff filed direct testimony recommending
a
base rate reduction in the range of $12 million to $20 million for SWEPCo’s
Louisiana jurisdiction customers, which included a 10% return on equity. The
recommended reduction range is subject to SWEPCo validating certain on-going
operations and maintenance expense levels and the recommended base rate
reduction does not include the impact of a proposed consolidated federal income
tax adjustment, which would increase the proposed rate reduction. SWEPCo filed
rebuttal testimony in October 2006 refuting the consultants’ recommendations. In
December 2006, the LPSC staff’s consultants filed reply testimony asserting that
SWEPCo’s Louisiana base rates are excessive by $17 million which includes a
proposed return on equity of 9.8%. SWEPCo filed testimony in the first quarter
of 2007. Hearings are expected to occur in early 2007. A decision is expected
in
mid-to-late 2007. At this time, management is unable to predict the outcome
of
this proceeding. If a rate reduction were ultimately ordered, it would adversely
impact future results of operations and cash flows.
The
amount that PSO
seeks to recover for fuel costs is currently being
reviewed. (Applies
to PSO.)
In
2002,
PSO experienced a $44 million under-recovery of fuel costs resulting from a
reallocation among AEP West companies of purchased power costs for periods
prior
to January 1, 2002. In July 2003, PSO filed with the OCC offering to collect
the
under-recovery over 18 months. An intervenor, the staff of the OCC and the
Attorney General of Oklahoma have made filings indicating that recovery should
be reduced substantially or disallowed altogether. These filings disputed the
allocation of AEP System off-system sales margins pursuant to an agreement
approved by FERC. In September 2003, the OCC expanded the case to include a
full
review of PSO’s 2001 fuel and purchased power practices. The allocation issue
was referred to an ALJ. The ALJ recommended that the OCC lacks authority to
examine whether PSO deviated from the FERC allocation methodology and that
any
such complaints should be addressed at the FERC. The OCC conducted a hearing
on
the jurisdictional matter in January 2005 but has not issued a decision.
If
the
OCC determines, as a result of the review, that a portion of PSO’s fuel and
purchased power costs should not be recovered, there could be an adverse effect
on PSO’s results of operations, cash flows and possibly financial condition.
The
internal allocation of AEP System off-system sales margins has been challenged.
(Applies
to APCo, CSPCo, I&M, KPCo and OPCo.)
Off-system
sales margins are allocated among the AEP System companies pursuant to a
FERC-approved agreement among those companies entered into at the time of the
merger with CSW. In November 2005, we filed with the FERC a proposed allocation
methodology to be used in 2006 and beyond. The original allocations have been
challenged in different forums, including PSO’s fuel clause recovery proceeding
before the OCC. In general, the challenges assert that AEP West companies,
acquired in the merger with CSW, are being allocated a disproportionately small
amount of the off-system sales margins. An ALJ in the OCC proceeding and,
separately, a federal district court in Texas have each held that the FERC
is
the only appropriate adjudicator of such challenges. This holding has been
affirmed by a federal appellate court. No proceeding questioning the allocation
of our off-system sales is currently before the FERC; the OCC, however, has
yet
to rule on whether it has jurisdiction over this issue. If the FERC or another
entity of competent authority were to retroactively allocate additional
off-system sales margins to the AEP West companies, the AEP East companies
may
be required to pay money to the AEP West companies. Any such payments
could
have an adverse effect on the results of operations, cash flows and possibly
financial condition of the AEP
East
companies.
The
base rates that certain of our utilities charge are currently capped or
frozen.
(Applies to AEP, CSPCo, I&M and OPCo.)
Base
rates charged to customers in Michigan and Ohio are currently either frozen
or
capped. To the extent our costs in these states exceed the applicable cap or
frozen rate, those costs are not recoverable from customers.
Certain
of our revenues and results of operations are subject to risks that are beyond
our control. (Applies
to each registrant.)
Unless
mitigated by timely and adequate regulatory recovery, the cost of repairing
damage to our utility facilities due to storms, natural disasters, wars,
terrorist acts and other catastrophic events, in excess of insurance coverage,
when applicable, may adversely impact our revenues, operating and capital
expenses and results of operations. Such events may also create additional
risks
related to the supply and/or cost of equipment and materials.
We
are exposed to nuclear generation risk.
(Applies to AEP and I&M.)
Through
I&M, we own the Cook Plant. It consists of two nuclear generating units for
a rated capacity of 2,143 MW, or 6% of our generation capacity. We are,
therefore, subject to the risks of nuclear generation, which include the
following:
There
can
be no assurance that I&M’s preparations or risk mitigation measures will be
adequate if and when these risks are triggered.
The
NRC
has broad authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generation facilities. In the event
of
non-compliance, the NRC has the authority to impose fines or shut down a unit,
or both, depending upon its assessment of the severity of the situation, until
compliance is achieved. Revised safety requirements promulgated by the NRC
could
necessitate substantial capital expenditures at nuclear plants such as ours.
In
addition, although we have no reason to anticipate a serious nuclear incident
at
our plants, if an incident did occur, it could harm our results of operations
or
financial condition. A major incident at a nuclear facility anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of
any
domestic nuclear unit. Moreover, a major incident at a nuclear facility in
the
U.S. could require us to make material contributory payments.
The
different regional power markets in which we compete or will compete in the
future have changing transmission regulatory structures, which could affect
our
performance in these regions.
(Applies to each registrant.)
Our
results are likely to be affected by differences in the market and transmission
regulatory structures in various regional power markets. Problems or delays
that
may arise in the operation of new regional transmission organization (RTO)
power
markets, may restrict our ability to sell power produced by our generating
capacity to certain markets if there is insufficient transmission capacity
available to fully support market operation. The rules governing the various
regional power markets may also change from time to time which could affect
our
costs or revenues. Because it remains unclear which companies will be
participating in the various regional power markets, or the manner in which
RTOs
will evolve or the regions they will cover, we are unable to assess fully the
impact that these power markets may have on our business.
AEP
East
companies joined PJM on October 1, 2004. SWEPCo and PSO are members of SPP.
In
February 2004, FERC granted RTO status to SPP, subject to fulfilling specified
requirements. In October 2004, the FERC issued an order granting final RTO
status to SPP subject to certain filings.
The
LPSC
has ordered the utilities subject to its jurisdiction, including SWEPCo, to
analyze and submit to them the costs and benefits of RTO options available
to
the utilities. Certain states in the region have undertaken and released a
study
investigating the costs and benefits of SPP developing into a RTO that
administers energy and associated markets.
To
the
extent we are faced with conflicting state and Federal requirements as to our
participation in RTOs, it could adversely affect our ability to operate and
recover transmission costs from retail customers. Management is unable to
predict the outcome of these transmission regulatory actions and proceedings
or
their impact on the timing and operation of RTOs, our transmission operations
or
future results of operations and cash flows.
The
amount we charged third parties for using our transmission facilities has been
reduced, is subject to refund and may not be completely restored in the
future. (Applies
to AEP and AEP
East companies.)
In
July
2003, the FERC issued an order directing PJM and the MISO to make compliance
filings for their respective tariffs to eliminate the transaction-based charges
for through and out (T&O) transmission service on transactions where the
energy is delivered within those RTOs. The elimination of the T&O rates
reduces the transmission service revenues collected by the RTOs and thereby
reduces the revenues received by transmission owners under the RTOs’ revenue
distribution protocols. To mitigate the impact of lost T&O revenues, the
FERC approved temporary replacement seams elimination cost allocation (SECA)
transition rates beginning in December 2004 and extending through March 2006.
Intervenors objected to this decision; therefore the SECA fees we collected
($220
million) are
subject to refund. Approximately
$19 million of the SECA revenues that we billed were never collected. The AEP
East zone public utilities filed a motion with the FERC to force payment of
these SECA billings.
A
hearing
was held in May 2006 to determine whether any of the SECA revenues should be
refunded. In August 2006, the ALJ issued an initial decision, finding that
the
rate design for the recovery of SECA charges was flawed and that a large portion
of the “lost revenues” reflected in the SECA rates were not recoverable. The ALJ
found that the SECA rates charged were unfair, unjust and discriminatory, and
that new compliance filings and refunds should be made. The ALJ also found
that
unpaid SECA rates must be paid in the recommended reduced amount. The FERC
has
not ruled on the matter. If the FERC upholds the decision of the ALJ, up to
$126
million of collected SECA rates could be refunded by the AEP East zone public
utilities. We have recorded provisions in the aggregate amount of $37 million
related to the potential refund of SECA rates pending settlement negotiations
with various intervenors.
SECA
transition rates expired at the end of March 2006
and did
not fully compensate AEP for ongoing lost T&O revenues.
As a
result of rate relief in certain jurisdictions, however, approximately 85%
of
the ongoing
lost T&O revenues
are now
being recovered from native load customers of AEP East companies in those
jurisdictions.
The
portion attributable to Virginia is being collected subject to
refund.
In
addition to seeking retail rate recovery from native load customers in the
applicable states, AEP and another member of PJM have filed an application
with
the FERC seeking compensation from other unaffiliated members of PJM for the
costs associated with those members’ use of our respective transmission assets.
A
majority of PJM members have filed in opposition to the proposal. Hearings
were
held in April 2006. An ALJ recommended a rate design that would result in
greater recovery for AEP than the proposal AEP had submitted. The ALJ also
recommended, however, that the design be phased-in, which could limit the amount
of recovery for AEP. The FERC has not yet ruled on this matter. Management
cannot at this time estimate the outcome of these proceedings.
Rate
regulation may delay or deny full recovery of costs. (Applies
to each registrant.)
Our
public utility subsidiaries currently provide service at rates approved by
one
or more regulatory commissions. These rates are generally regulated based on
an
analysis of the applicable utility’s expenses incurred in a test year. Thus, the
rates a utility is allowed to charge may or may not match its expenses at any
given time. Additionally, there may also be a delay between the timing of when
these costs are incurred and when these costs are recovered. While rate
regulation is premised on providing a reasonable opportunity to earn a
reasonable rate of return on invested capital, there can be no assurance that
the applicable regulatory commission will judge all of our costs to have been
prudently incurred or that the regulatory process in which rates are determined
will always result in rates that will produce full recovery of our costs in
a
timely manner.
We
operate in a non-uniform and fluid regulatory environment.
(Applies to each registrant.)
In
addition to the multiple levels of state regulation at the states in which
we
operate, our business is subject to extensive federal regulation. There can
be
no assurance that (1) the federal legislative and regulatory initiatives (which
have occurred over the past few years and which have generally facilitated
competition in the energy sector) will continue or will not be reversed or
(2)
state regulation will not become significantly more restrictive. Further
alteration of the regulatory landscape in which we operate will impact the
effectiveness of our business plan and may, because of the continued
uncertainty, harm our financial condition and results of
operations.
At
times, demand for power could exceed our supply capacity.
(Applies to each registrant other than TCC and TNC.)
We
are
currently obligated to supply power in parts of eleven states. From time to
time, because of unforeseen circumstances, the demand for power required to
meet
these obligations could exceed our available generation capacity. If this
occurs, we would have to buy power from the market. We may not always have
the
ability to pass these costs on to our customers because some of the states
we
operate in do not allow us to increase our rates in response to increased fuel
cost charges. Since these situations most often occur during periods of peak
demand, it is possible that the market price for power at that time would be
very high. Even if a supply shortage were brief, we could suffer substantial
losses that could reduce our results of operations.
Risks
Related to Market, Economic or Financial Volatility
Downgrades
in our credit ratings could negatively affect our ability to access capital
and/or to operate our power trading businesses.
(Applies to each registrant other than AEGCo.)
Following
the bankruptcy of Enron, the credit ratings agencies initiated a thorough review
of the capital structure and the quality and stability of earnings of energy
companies, including us. The agencies revised ratings at that time. Further
negative ratings actions could constrain the capital available to our industry
and could limit our access to funding for our operations. Our
business is capital intensive, and we are dependent upon our ability to access
capital at rates and on terms we determine to be attractive. If our ability
to
access capital becomes significantly
constrained, our interest costs will likely increase and our financial condition
could be harmed and future results of operations could be adversely
affected.
If
Moody’s or S&P
were
to
downgrade the long-term rating of any of the registrants,
particularly below investment grade, the borrowing costs of that registrant
would increase, which would diminish its financial results. In addition, the
registrant’s potential pool of investors and funding sources could
decrease.
Our
power
trading business relies on the investment grade ratings of our individual public
utility subsidiaries’ senior unsecured long-term debt. Most of our
counterparties require the creditworthiness of an investment grade entity to
stand behind transactions. If those ratings were to decline below investment
grade, our ability to operate our power trading business profitably would be
diminished because we would likely have to deposit cash or cash-related
instruments which would reduce our profits.
AEP
has no income or cash flow apart from dividends paid or other obligations due
it
from its subsidiaries. (Applies
to AEP.)
AEP
is a
holding company and has no operations of its own. Its ability to meet its
financial obligations associated with its indebtedness and to pay dividends on
its common stock is primarily dependent on the earnings and cash flows of its
operating subsidiaries, primarily its regulated utilities, and the ability
of
its subsidiaries to pay dividends to, or repay loans from, AEP. Its
subsidiaries are separate and distinct legal entities that have no obligation
(apart from loans from AEP) to provide AEP with funds for its payment
obligations, whether by dividends, distributions or other payments. Payments
to
AEP by its subsidiaries are also contingent upon their earnings and business
considerations. In addition, any payment of dividends, distributions or advances
by the utility subsidiaries to AEP would be subject to regulatory or contractual
restrictions.
Our
operating results may fluctuate on a seasonal and quarterly
basis.
(Applies to each registrant.)
Electric
power generation is generally a seasonal business. In many parts of the country,
demand for power peaks during the hot summer months, with market prices also
peaking at that time. In other areas, power demand peaks during the winter.
As a
result, our overall operating results in the future may fluctuate substantially
on a seasonal basis. The pattern of this fluctuation may change depending on
the
terms of power sale contracts that we enter into. In addition, we have
historically sold less power, and consequently earned less income, when weather
conditions are milder. Unusually mild weather in the future could diminish
our
results of operations and harm our financial condition.
Conversely, unusually extreme weather conditions could increase AEP’s results of
operations in a manner that would not likely be sustainable.
Parties
we have engaged to provide construction materials or services may fail to
perform their obligations, which could harm our results of
operations.
(Applies to each registrant.)
Our
business plan calls for extensive investment in capital improvements and
additions, including the installation of environmental upgrades, construction
of
additional generation units and transmission facilities as well as other
initiatives. We are exposed to the risk of substantial price increases in the
costs of materials used in construction. We have engaged numerous contractors
and entered into a large number of agreements to acquire the necessary materials
and/or obtain the required construction related services. As a result, we are
also exposed to the risk that these contractors and other counterparties could
breach their obligations to us. Should the counterparties to these arrangements
fail to perform, we may be forced to enter into alternative arrangements at
then-current market prices that may exceed our contractual prices and almost
certainly cause delays in that and related projects. Although our agreements
are
designed to mitigate the consequences of a potential default by the
counterparty, our actual exposure may be greater than these mitigation
provisions. This would cause our financial results to be diminished, and we
might incur losses or delays in completing construction.
Changes
in commodity prices may increase our cost of producing power or decrease the
amount we receive from selling power, harming our financial
performance.
(Applies to each registrant.)
We
are
heavily exposed to changes in the price and availability of coal because most
of
our generating capacity is coal-fired. We have contracts of varying durations
for the supply of coal for most of our existing generation capacity, but as
these contracts end or otherwise are not honored, we may not be able to purchase
coal on terms as favorable as the current contracts. Similarly, we are heavily
exposed to changes in the price and availability of emission allowances. We
use
emission allowances based on the amount of coal we use as fuel and the
reductions achieved through emission controls and other measures. According
to
our estimates we have procured sufficient emission allowances to cover our
projected needs for the next two years and for much of the projected needs
for
periods beyond that. At some point, however, we may have to obtain additional
allowances and those purchases may not be on as favorable terms as those
currently obtained.
We
also
own natural gas-fired facilities, which increases our exposure to market prices
of natural gas. Natural gas prices tend to be more volatile than
prices for other fuel sources.
The
price
trends for coal, natural gas and emission allowances have shown material
increases in the recent past. Changes in the cost of coal, emission allowances
or natural gas and changes in the relationship between such costs and the market
prices of power will affect our financial results. Since the prices we obtain
for power may not change at the same rate as the change in coal, emission
allowances or natural gas costs, we may be unable to pass on the changes in
costs to our customers. In addition, the prices we can charge our retail
customers in some jurisdictions are capped.
In
addition, actual power prices and fuel costs will differ from those assumed
in
financial projections used to value our trading and marketing transactions,
and
those differences may be material. As a result, our financial results may be
diminished in the future as those transactions are marked to
market.
In
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