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, through 2008, 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 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, 2007, the subsidiaries of AEP had a total of 20,861 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 956,000 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, 2007, APCo and its wholly owned
subsidiaries had 2,497 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 is interconnected
with the following unaffiliated utility companies: Carolina Power & Light
Company, Duke Carolina 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 746,000 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, 2007, CSPCo had 1,265 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 is
interconnected with the following unaffiliated utility companies: Duke Ohio,
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 583,000 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, 2007,
I&M had 2,687 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. This lease
currently extends through February 2010. In addition to its AEP
System interconnections, I&M is interconnected with the following
unaffiliated utility companies: Central Illinois Public Service Company, Duke
Ohio, Commonwealth Edison Company, Consumers Energy Company, Illinois Power
Company, Indianapolis Power & Light Company, Louisville Gas and Electric
Company, Northern Indiana Public Service Company, Duke Indiana 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, 2007, KPCo had 471 employees. In addition to its AEP System
interconnections, KPCo 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 47,000 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, 2007, Kingsport Power Company had 57 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, 2007,
OPCo had 2,351 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 is interconnected with the following unaffiliated utility
companies: Duke Ohio, 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 525,000 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, 2007, PSO had 1,255 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 is interconnected with Ameren Corporation, Empire District
Electric Company, Oklahoma Gas and Electric Company, Southwestern Public Service
Company 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 467,000 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, 2007,
SWEPCo had 1,578 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 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 753,000 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, 2007, TCC had 1,195 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 184,000 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, 2007, TNC had 373 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, 2007, WPCo had 61 employees.
AEGCo
(organized in Ohio in
1982) is an electric generating company. AEGCo sells power at wholesale to
I&M, CSPCo 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 affiliated companies. The
executive officers of AEP and certain of its public utility subsidiaries are
employees of AEPSC. At December 31, 2007, AEPSC had 6,151
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, 2007 are as follows:
Description
|
AEP
System(a)
|
APCo
|
CSPCo
|
I&M
|
|
(in
thousands)
|
UTILITY
OPERATIONS:
|
|
|
|
Retail
Sales
|
|
|
|
|
Residential
Sales
|
$
3,991,000
|
$
787,710
|
$
682,184
|
$
418,953
|
Commercial
Sales
|
2,906,000
|
387,323
|
619,396
|
328,754
|
Industrial
Sales
|
2,674,000
|
540,968
|
272,673
|
360,341
|
PJM
Net Charges
|
(131,000)
|
(43,803)
|
(24,433)
|
(24,613)
|
Provision
for Rate Refund
|
(4,000)
|
(12,996)
|
-
|
-
|
Other
Retail Sales
|
192,000
|
49,464
|
5,441
|
6,209
|
Total
Retail
|
9,628,000
|
1,708,666
|
1,555,261
|
1,089,644
|
Wholesale
|
|
|
|
|
Off-System
Sales
|
2,003,000
|
597,556
|
323,934
|
591,893
|
Transmission
|
145,000
|
(17,355)
|
(11,492)
|
5,603
|
Total
Wholesale
|
2,148,000
|
580,201
|
312,442
|
597,496
|
Other
Electric Revenues
|
216,000
|
44,581
|
25,342
|
21,058
|
Other
Operating Revenues
|
109,000
|
10,755
|
7,155
|
27,367
|
Sales
To Affiliates
|
-
|
263,066
|
143,112
|
307,627
|
Total
Utility Operating Revenues
|
12,101,000
|
2,607,269
|
2,043,312
|
2,043,192
|
OTHER
|
1,279,000
|
-
|
-
|
-
|
TOTAL
REVENUES
|
$
13,380,000
|
$
2,607,269
|
$
2,043,312
|
$
2,043,192
|
Description
|
OPCo
|
PSO
|
SWEPCo
|
|
(in
thousands)
|
UTILITY
OPERATIONS:
|
|
|
|
Retail
Sales
|
|
|
|
Residential
Sales
|
$
592,348
|
$
482,963
|
$
423,504
|
Commercial
Sales
|
385,783
|
352,155
|
367,280
|
Industrial
Sales
|
629,589
|
307,833
|
287,590
|
PJM
Net Charges
|
(28,901)
|
-
|
-
|
Provision
for Rate Refund
|
-
|
-
|
(16,877)
|
Other
Retail Sales
|
9,258
|
88,346
|
7,561
|
Total
Retail
|
1,588,077
|
1,231,297
|
1,069,058
|
Wholesale
|
|
|
|
Off-System
Sales
|
415,726
|
62,968
|
258,383
|
Transmission
|
(13,320)
|
16,641
|
37,351
|
Total
Wholesale
|
402,406
|
79,609
|
295,734
|
Other
Electric Revenues
|
29,149
|
11,013
|
63,821
|
Other
Operating Revenues
|
14,823
|
4,525
|
1,747
|
Sales
to Affiliates
|
779,757
|
69,106
|
53,102
|
Total
Utility Operating Revenues
|
2,814,212
|
1,395,550
|
1,483,462
|
OTHER
|
-
|
-
|
-
|
TOTAL
REVENUES
|
$
2,814,212
|
$
1,395,550
|
$
1,483,462
|
(a)
|
Includes
revenues of other subsidiaries not shown. Intercompany transactions have
been eliminated for the year ended December 31,
2007.
|
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, 2007, 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 2007 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
AEP’s
senior unsecured debt is rated Baa2 by Moody’s and BBB by S&P and
Fitch. AEP’s commercial paper is rated Prime-2 by Moody’s, A2 by
S&P and F2 by Fitch. There were no changes in the ratings or
rating outlook for AEP by Moody’s, S&P or Fitch during 2007. In
February 2008 Fitch downgraded the senior unsecured debt rating of PSO to BBB+
with stable outlook. Fitch downgraded the senior unsecured debt
rating of TCC (to BBB+) in April 2007 and placed it on negative outlook until
November 2007, when Fitch restored its stable outlook. Fitch revised
TNC’s outlook from negative to stable in April 2007. Moody’s placed
the senior unsecured debt rating of APCo, OPCo, SWEPCo and TCC on negative
outlook in January 2008. Moody’s assigns the following ratings to the
senior unsecured debt of these companies: APCo Baa2, OPCo A3, SWEPCo
Baa1 and TCC Baa2. See
Management’s Financial Discussion
and Analysis of Results of Operations
, included in the 2007 Annual
Reports, under the heading entitled
Financial Condition
for
additional information with respect to the credit ratings of the
registrants.
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:
·
|
Global
climate change and legislative responses to it, including limitations on
CO
2
emissions. See
Management’s Financial
Discussion and Analysis of Results of Operations
under the headings
entitled
Environmental
Matters – Potential Regulation of
CO
2
and GHG
Emissions.
|
·
|
The
CAA and CAAA and state laws and regulations (including State
Implementation Plans) that require compliance, obtaining permits and
reporting as to air emissions. See
Management’s Financial
Discussion and Analysis of Results of Operations
under the headings
entitled
Environmental
Matters -
Clean
Air Act Requirements
and
Estimated Air Quality
Environmental Investments
.
|
·
|
Litigation
with the federal and certain state governments and certain special
interest groups regarding regulated air emissions and/or whether emissions
from coal-fired generating plants cause or contribute to global climate
changes. See
Management’s Financial
Discussion and Analysis of Results of Operations
under the heading
entitled
Environmental
Matters
-
Environmental Litigation
and Note 6 to the consolidated financial statements entitled
Commitments, Guarantees and
Contingencies
, included in the 2007 Annual Reports, for further
information.
|
·
|
Rules
issued by the EPA and certain states that require substantial reductions
in SO
2
,
mercury and NOx emissions, which have compliance dates that take effect
periodically through as late as 2018. AEP is installing (and has
installed) emission control technology and is taking other measures to
comply with required reductions. See
Management’s Financial
Discussion and Analysis of Results of Operations
under the headings
entitled
Environmental
Matters - Clean Air Act Requirements
and
Estimated Air Quality
Environmental Investments
included in the 2007 Annual Reports for
further information.
|
·
|
CERCLA,
which imposes costs for environmental remediation upon owners and previous
owners of sites, as well as transporters and generators of hazardous
material disposed of at such sites. See Note 6 to the
consolidated financial statements entitled
Commitments, Guarantees and
Contingencies
, included in the 2007 Annual Reports, under the
heading entitled
The
Comprehensive Environmental Response Compensation and Liability Act
(
Superfund) and State
Remediation
for further information
.
|
·
|
The
Federal Clean Water Act, which prohibits the discharge of pollutants into
waters of the United States except pursuant to appropriate permits. See
Management’s Financial
Discussion and Analysis of Results of Operations
, included in the
2007 Annual Reports, under the heading entitled
Environmental Matters -
Clean Water Act
Regulations
for additional
information.
|
·
|
Solid
and hazardous waste laws and regulations, which govern the management and
disposal of certain wastes. The majority of solid waste created from the
combustion of coal and fossil fuels is fly ash and other coal combustion
byproducts, which the EPA has determined are not hazardous waste subject
to RCRA.
|
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 2007 Annual Reports,
for further information
with respect to environmental issues
.
While we
expect to recover our expenditures for pollution control technologies,
replacement generation and associated operating costs from customers through
regulated rates (in regulated jurisdictions) or market prices (in Ohio and
Texas), without such recovery 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. In October 2007, we
settled the New Source Review litigation with the EPA, the United States
Department of Justice, various states and special interest
groups. The litigation challenged whether modifications to or
maintenance of certain coal-fired generating plants required additional
permitting or pollution control technology. In settling, we agreed to
invest in additional environmental controls for our plants before
2019. We also paid a $15 million civil penalty and will provide $36
million for environmental projects coordinated with the federal government and
$24 million to the states for environmental mitigation. 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 2007 Annual Reports, for more information
regarding the settled litigation and other environmental
matters.
Environmental
Investments
Investments
related to improving AEP System plants’ environmental performance and compliance
with air and water quality standards during 2005, 2006 and 2007 and the current
estimates for 2008, 2009 and 2010 are shown below, in each case excluding AFUDC
or capitalized interest. AEP expects to make substantial investments in addition
to the amounts set forth below in future years in connection with the
modification and addition of facilities at generating plants for environmental
quality controls. Such future investments are needed in order to
comply with air and water quality standards which have been adopted and have
deadlines for compliance after 2010 or have been proposed and may be
adopted. Future investments could be significantly greater if
emissions reduction requirements are accelerated or otherwise become more
onerous or if CO
2
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 2007 Annual Reports, for more information
regarding environmental expenditures in general.
Historical
and Projected Environmental Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
Actual
|
|
|
Actual
|
|
|
Actual
|
|
|
Estimate
|
|
|
Estimate
|
|
|
Estimate
|
|
(in thousands)
|
|
Total
AEP System*
|
|
$
|
811,400
|
|
|
$
|
1,366,200
|
|
|
$
|
994,100
|
|
|
$
|
875,300
|
|
|
$
|
606,400
|
|
|
$
|
394,200
|
|
APCo
|
|
|
231,200
|
|
|
|
532,800
|
|
|
|
351,900
|
|
|
|
315,900
|
|
|
|
255,900
|
|
|
|
177,100
|
|
CSPCo
|
|
|
32,200
|
|
|
|
138,900
|
|
|
|
130,000
|
|
|
|
139,900
|
|
|
|
66,800
|
|
|
|
23,700
|
|
I&M
|
|
|
62,900
|
|
|
|
23,200
|
|
|
|
9,300
|
|
|
|
51,500
|
|
|
|
20,500
|
|
|
|
3,100
|
|
OPCo
|
|
|
458,600
|
|
|
|
660,800
|
|
|
|
481,700
|
|
|
|
291,700
|
|
|
|
179,200
|
|
|
|
43,100
|
|
PSO
|
|
|
200
|
|
|
|
500
|
|
|
|
1,500
|
|
|
|
25,800
|
|
|
|
22,100
|
|
|
|
47,000
|
|
SWEPCo
|
|
|
11,900
|
|
|
|
21,000
|
|
|
|
14,300
|
|
|
|
33,000
|
|
|
|
32,700
|
|
|
|
66,800
|
|
*
|
Includes
expenditures of both the subsidiaries shown below and other subsidiaries
not shown. The figures reflect
construction
expenditures, not investments in subsidiary companies. Excludes
discontinued operations.
|
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 37,000 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, 2007, the member-load-ratios were as follows:
|
Peak
Demand
(MW)
|
Member-Load
Ratio
(%)
|
APCo
|
8,132
|
33.1
|
CSPCo
|
4,713
|
19.2
|
I&M
|
4,528
|
18.5
|
KPCo
|
1,665
|
6.8
|
OPCo
|
5,491
|
22.4
|
Ohio’s
electric restructuring law, 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. As permitted by the Ohio Act,
CSPCo and OPCo can implement market-based rates effective January 2009,
following the expiration of their RSPs on December 31, 2008. CSPCo
and OPCo have been involved in discussions with various stakeholders in Ohio
about proposed 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 2007 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, 2005, 2006 and 2007:
|
2005
|
2006
|
2007
|
|
(in
thousands)
|
APCo
|
$288,000
|
$319,500
|
$454,800
|
CSPCo
|
285,600
|
281,700
|
173,000
|
I&M
|
(197,400)
|
(146,100)
|
(93,200)
|
KPCo
|
42,200
|
38,800
|
41,200
|
OPCo
|
(418,400)
|
(493,900)
|
(575,800)
|
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 their business operations
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, 2005, 2006
and 2007:
|
2005
|
2006
|
2007
|
|
(in
thousands)
|
PSO
|
$27,600
|
$(15,300)
|
$(17,500)
|
SWEPCo
|
(27,500)
|
9,900
|
16,800
|
TCC
|
0
|
0
|
0
|
TNC
|
(100)
|
5,400
|
700
|
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 Ohio considers continuing to transition to
the use of market rates for generation and as Virginia completes it final year
of transition before returning to a form of cost-based regulation. 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. Because TCC and TNC have
exited the generation business, these two companies are no longer parties to the
System Integration 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, 2007,
counterparties and exchanges have posted approximately $43 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 $77 million with counterparties and
exchanges). Since open trading contracts are valued based on market
power prices, exposures change daily.
Fuel
Supply
The
following table shows the sources of fuel used by the AEP System:
|
2005
|
2006
|
2007
|
Coal
and Lignite
|
83%
|
85%
|
85%
|
Natural
Gas
|
6%
|
6%
|
6%
|
Nuclear
|
10%
|
9%
|
9%
|
Hydroelectric
and other
|
1%
|
<1%
|
<1%
|
Variations
in the generation of nuclear power are primarily related to refueling and
maintenance outages. 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 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 coal from different coal regions and sources
that have different heat and sulfur contents. This rebalancing is an
ongoing process that is expected to continue, significantly enabled by the
installation of scrubbers at a number of our generating facilities. Management
believes 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, leases or controls more than 8,400 railcars, 692 barges, 16 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
plants during the past three years and the average delivered price of coal
purchased by System companies:
|
2005
|
2006
|
2007
|
Total
coal delivered to AEP System plants (thousands of tons)
|
72,321
|
76,045
|
72,644
|
Average
price per ton of purchased coal
|
$32.84
|
$35.27
|
$36.65
|
The coal
supplies at AEP System plants vary from time to time depending on various
factors, including, but not limited to, demand for electric power, unit outages,
transportation infrastructure limitations, space limitations, plant coal
consumption rates, labor issues and weather conditions which may interrupt
production or deliveries. At December 31, 2007, the System’s coal inventory was
approximately 29 - 33 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 108 billion cubic feet of natural
gas during 2007 for generating power. 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. I&M also leases nuclear
fuel.
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 entered into an agreement to
provide for onsite 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 spent nuclear fuel disposal program. In 2006, when the most
recent study was done, the estimated cost of decommissioning and disposal of
low-level radioactive waste for the Cook Plant ranged from $733 million to $1.3
billion in 2006 non-discounted dollars. At December 31, 2007, the
total decommissioning trust fund balance for the Cook Plant was $1.057
billion. The ultimate cost of retiring the Cook Plant may be
materially different from estimates and funding targets as a result of
the:
·
|
Type
of decommissioning plan selected;
|
·
|
Escalation
of various cost elements (including, but not limited to, general inflation
and the cost of energy);
|
·
|
Further
development of regulatory requirements governing
decommissioning;
|
·
|
Technology
available at the time of decommissioning differing significantly from that
assumed in studies;
|
·
|
Availability
of nuclear waste disposal facilities;
and
|
·
|
Availability
of a DOE facility for permanent storage of spent nuclear
fuel.
|
Accordingly,
management is unable to provide assurance that the ultimate cost of
decommissioning the Cook Plant will not be significantly different than current
projections. We will seek recovery from customers through our
regulated rates if actual decommissioning costs exceed our
projections. See Note 10 to the consolidated financial statements,
entitled
Nuclear
,
included in the 2007 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 license low-level radioactive waste disposal sites
which currently accept low-level radioactive waste from
Michigan. I&M’s access to the Barnwell, South Carolina facility
is currently allowed through the end of fiscal year 2008. With some
modifications to existing facilities, I&M will have capacity for onsite
storage of that waste currently shipped to Barnwell, South Carolina for the
duration of its licensed operation of Cook Plant. There is currently
no set date limiting I&M’s access to the Utah facility; however this
facility does not accept all classifications of low level waste.
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 2012, 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
I&M
:
The Unit Power Agreement
between AEGCo and I&M, dated March 31, 1982, 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 a demand charge for the right to receive such power
(and an energy charge for any associated energy taken by
I&M). The 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 that I&M would have paid AEGCo under the
terms of the Unit Power Agreement between AEGCo and I&M for such
entitlement. The KPCo unit power agreement expires in December
2022.
CSPCo
:
The Unit Power Agreement
between AEGCo and CSPCo, dated March 15, 2007, provides for the sale by AEGCo to
CSPCo of all the capacity and associated unit contingent energy and ancillary
services available to AEGCo at the Lawrenceburg Plant that are scheduled and
dispatched by CSPCo. CSPCo is obligated to pay a capacity charge
(whether or not power is available from the Lawrenceburg Plant), the fuel,
operating and maintenance charges associated with the energy dispatched by
CSPCo, and to reimburse AEGCo for other costs associated with the operation and
ownership of the Lawrenceburg Plant. The agreement will continue in
effect until December 31, 2017 unless extended as set forth in the
agreement.
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 began construction of flue gas
desulfurization (sulfur dioxide scrubber) projects and the associated scrubber
waste disposal landfills. In November 2007, OVEC’s Board of Directors
authorized additional interim capital expenditures of up to $82.8 million for
completion of the associated scrubber waste disposal landfills. If
approved, the estimated total cost to complete the scrubber and landfill
projects would be in excess of $1 billion, which OVEC would expect to finance
through issuing debt.
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 –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 –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, 2007 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, 2005, 2006 and 2007:
|
2005
|
2006
|
2007
|
|
(in
thousands)
|
APCo
|
$8,900
|
$(16,000)
|
$(25,000)
|
CSPCo
|
34,600
|
46,000
|
51,900
|
I&M
|
(47,000)
|
(37,000)
|
(34,600)
|
KPCo
|
(3,500)
|
(2,000)
|
(800)
|
OPCo
|
7,000
|
9,000
|
8,500
|
Transmission
Coordination Agreement:
PSO, SWEPCo, TCC, TNC
and AEPSC are parties to the TCA, which has been approved by the
FERC. Under the TCA, a coordinating committee 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. Pursuant to the TCA, the
AEP West companies have delegated to AEPSC responsibility for 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, 2005, 2006 and
2007:
|
2005
|
2006
|
2007
|
|
(in
thousands)
|
PSO
|
$3,500
|
$1,800
|
500
|
SWEPCo
|
5,200
|
(1,900)
|
(500)
|
TCC
|
(3,800)
|
1,100
|
1,100
|
TNC
|
(4,900)
|
(1,000)
|
(1,100)
|
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 –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
allocation of transmission costs and revenues
and
|
·
|
The
allocation of third-party transmission costs and revenues and System
dispatch costs.
|
The
System Transmission Integration Agreement contemplates that additional service
schedules may be added as circumstances warrant.
Regional
Transmission Organizations
The AEP
East Companies are members of PJM (a FERC-approved RTO). SWEPCo and
PSO are members of the SPP (another FERC-approved RTO). RTOs operate,
plan and control utility transmission assets in a manner designed to provide
open access to such assets in a way that prevents discrimination between
participants owning transmission assets and those that do not. 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
2007 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 transmission and/or retail generation sales in certain of its jurisdictions,
AEP’s public utility subsidiaries’ retail rates and certain other matters are
subject to traditional regulation by the state utility
commissions. 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, 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 for electric service are unbundled for
generation, transmission and distribution service. 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, with rates set on a cost-of-service basis. In January 2008,
I&M filed for an increase in its Indiana base rates of $82 million based on
a return on equity of 11.5% and a September 30, 2007 test year. The
base rate increase includes a $69 million reduction in depreciation. The filing
requests trackers for certain variable components of the cost of service
including additional PJM costs, reliability enhancement costs, demand side
management/energy efficiency costs, off-system sales margins and net
environmental compliance costs. The trackers would increase annual
revenues by $46 million. I&M proposes to share 50% of an
estimated $96 million of off-system sales margins with ratepayers with a
guaranteed minimum of $20 million. A decision is expected from the
IURC in early 2009.
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, 2007. 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). Retail
generation rates are 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 are frozen from their levels as of December 31, 2005 through
December 31, 2008. Transmission services will continue to be provided at rates
based on rates established by the FERC. CSPCo and OPCo have been involved in
discussions with various stakeholders in Ohio about pending 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 2007 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 in the year following 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 and the OCC
issued a final order in October 2007. See Note 4 to the consolidated
financial statements, entitled
Rate Matters
, included in the
2007 Annual Reports, for additional information.
Texas:
TCC has sold all of its
generation assets. TNC has one active generation unit, however, all
of the output from that unit is sold to a non-utility affiliate pursuant to a
20-year agreement. Most retail customers in TCC’s and TNC’s ERCOT
service area of Texas are served through non-affiliated Retail Electric
Providers (“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
granted increases during 2007. See Note 4 to the consolidated
financial statements, entitled
Rate Matters
included in the
2007 Annual Reports, for additional information. In August 2006, the
PUCT delayed competition in the SPP area of Texas until at least January 1,
2011. As such, the PUCT continues to approve base and fuel rates for SWEPCo’s
Texas operations.
Virginia:
APCo currently provides
retail electric service in Virginia at unbundled rates. In April
2007, the Virginia legislature adopted a comprehensive law providing for the
re-regulation of electric utilities’ generation and supply rates after the
December 31, 2008 expiration of capped rates. The law
provides for, among other things, biennial rate reviews beginning in 2009; rate
adjustment clauses for the recovery of a variety of costs and a minimum allowed
return on equity which will be based on the average earned return on equity of
regional vertically integrated electric utilities. The law also
provides that utilities may retain a minimum of 25% of the margins from
off-system sales with the remaining margins from such sales credited against
fuel factor expenses with a true-up to actual.
In May 2007, the VSCC approved an
overall annual increase in base rates. In December 2007, the VSCC
approved recovery of certain recurring environmental and reliability costs (the
first of several anticipated requests for costs expected to be
incurred). In February 2008, the VSCC approved an adjustment in
APCO’s fuel factor and the submission of PJM-related costs in fuel factor review
and recovery, and authorized APCo to retain a share of margins from its
off-system sales. For a more complete discussion of these matters, see Note 4 to
the consolidated financial statements, entitled
Rate Matters
, included in the
2007 Annual Reports.
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
June 2007, the WVPSC approved a settlement agreement that provided for recovery
of additional costs effective July 1, 2007. See Note 4 to the
consolidated financial statements, entitled
Rate Matters
, included in the
2007 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:
|
|
|
|
|
|
Fuel Clause Rates
(
4)
|
|
|
|
|
|
|
|
|
|
|
Off-System
Sales Profits
|
|
Percentage
of AEP System
|
|
|
Status
of Base Rates for
|
|
|
|
Shared
with
|
Retail
|
Jurisdiction
|
|
Power
Supply
|
|
Energy
Delivery
|
|
Status
|
|
Ratepayers
|
|
Revenues
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
See
footnote 2
|
|
Distribution
frozen through 2008 (2)
|
|
None
|
|
Not
applicable
|
|
33%
|
Oklahoma
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes
|
|
13%
|
Texas
ERCOT
|
|
Not
applicable (3)
|
|
Not
capped or frozen
|
|
Not
applicable
|
|
Not
applicable
|
|
8%
|
Texas
SPP
|
|
Not
capped or frozen (3)
|
|
Not
capped or frozen
|
|
Active
|
|
Yes
|
|
5%
|
Indiana
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
No
|
|
9%
|
Virginia
|
|
Capped
until 12/31/08
|
|
Capped
until 12/31/08
|
|
Active
|
|
Yes
|
|
9%
|
West
Virginia
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes
|
|
10%
|
Louisiana
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes,
above base levels
|
|
4%
|
Kentucky
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes,
above and below base levels
|
|
4%
|
Arkansas
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes,
above base levels
|
|
2%
|
Michigan
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes,
in some areas
|
|
2%
|
Tennessee
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
No
|
|
1%
|
(1)
|
Represents
the percentage of revenues from sales to retail customers from AEP utility
companies operating in each state to the total AEP System revenues from
sales to retail customers for the year ended December 31,
2007.
|
(2)
|
The
PUCO has approved the rate stabilization plan filed by CSPCo and OPCo that
began after the market development period and extends through December 31,
2008 during which OPCo’s retail generation rates will increase 7% annually
and CSPCo’s retail generation rates will increase 3%
annually. Distribution rates are frozen, with certain
exceptions, through December 31, 2008. See Note 4 to the
consolidated financial statements, entitled
Rate
Matters
.
|
(3)
|
TCC
and TNC are no longer in the retail generation supply
business. TCC and TNC provide only regulated delivery services
in ERCOT. SWEPCo is vertically integrated utility that provides
retail electric service in the SPP area of
Texas.
|
(4)
|
Includes,
where applicable, fuel and fuel portion of purchased
power.
|
FERC
Under the
FPA, the FERC regulates rates for interstate sales at wholesale, transmission of
electric power, accounting and other matters, including construction and
operation of hydroelectric projects. The FERC regulations require AEP to provide
open access transmission service at FERC-approved rates. The FERC also regulates
unbundled transmission service to retail customers. The 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 the FERC, under which much of its wholesale marketing activity takes
place. The FERC requires 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 FERC also requires 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. Utilities are permitted to seek recovery of certain
prudently incurred stranded costs that result from unbundled transmission
services.
The FERC
oversees 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 the 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 are members of PJM. SWEPCo and PSO are members
of SPP.
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 the 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 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. Customer Choice also began in Virginia on January 1, 2002, but
will end beginning in 2009 pursuant to the passage of legislation providing for
the re-regulation of electric utilities’ generation and supply
rates.
Ohio
Restructuring
Currently,
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 RSPs 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 2007 Annual Reports
,
for a discussion of the impact of restructuring on distribution rates.
The PUCO authorized CSPCo and OPCo to remain functionally separated through
2008.
The Ohio
Act requires CSPCo and OPCo to begin implementing market-based rates on January
1, 2009, following the expiration of their RSPs. However, in August
2007, legislation was introduced that would significantly reduce the likelihood
of CSPCo’s and OPCo’s ability to charge market-based rates for generation at the
expiration of their RSPs. The legislation has been passed by the Ohio
Senate and is being considered by the Ohio House of
Representatives. AEP management is working closely with various
stakeholders to achieve a principled, fair and well-considered approach to
electric supply pricing.
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:
|
·
|
gave
Texas customers the opportunity to choose their REP beginning January 1,
2002 (delayed until at least 2011 in the SPP portion of
Texas),
|
|
·
|
required
each utility to legally separate into a REP, a power generation company
and a transmission and distribution utility,
and
|
|
·
|
required
that REPs provide electricity at generally unregulated rates, except that
until January 1, 2007 the prices that could be charged to residential and
small commercial customers by REPs affiliated with a utility within the
affiliated utility’s service area were set by the PUCT, until certain
conditions in the Texas Act were
met.
|
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. 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
2007 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,
2007, 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
Re-regulation
In April
2007, the Virginia legislature adopted a comprehensive law providing for the
re-regulation of electric utilities’ generation and supply rates after the
December 31, 2008 expiration of capped rates. The law
provides for, among other things, biennial rate reviews beginning in 2009; rate
adjustment clauses for the recovery of a variety of costs and a minimum allowed
return on equity which will be based on the average earned return on equity of
regional vertically integrated electric utilities. The law also
provides that utilities may retain a minimum of 25% of the margins from
off-system sales with the remaining margins from such sales credited against
fuel factor expenses with a true-up to actual.
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 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, and approved by, the various state commissions.
Occasionally, these rates are negotiated with the customer, and then filed with
the state commissions for approval. The public utility subsidiaries of AEP
believe that they are unlikely to be materially affected by this competition in
an adverse manner.
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
Operations 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 of 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 charged affiliated customers rates that
reflected our costs. The MEMCO operations include approximately 1,992
barges, 38 towboats and 14 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. The industry continues
to experience 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.
Our
Generation and Marketing Segment consists of non-utility generating assets and 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 310 MW of domestic wind power facilities and 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.
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 2007 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. Litigation in
connection with that power agreement has been settled. For more
information, 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 2007 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.
While Indiana permits the recovery of
prudently incurred
costs,
our request for
rate recovery may not be approved.
(Applies to AEP and
I&M.)
In
January 2008, I&M filed a request to increase base rates in its Indiana
jurisdiction by approximately $82 million. The request included a return on
equity of 11.5% and the ability to introduce additional riders. The
requested increase is attributable to additional costs relating to operating in
the PJM, reliability enhancement, demand side management, additional off-system
sales margin sharing and environmental compliance costs. While
regulation in Indiana provides for a return on costs prudently incurred, there
can be no assurance that the IURC will approve all of the costs included in our
filing or that this process will result in rates providing full recovery in a
timely manner. If the IURC denies the requested rate recovery, it
could adversely impact future results of operations, cash flows and financial
conditions.
The internal allocation of AEP System
off-system sales margins has been challenged.
(Applies to APCo, CSPCo,
I&M 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 a PSO
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. The OCC 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. If the FERC 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.
We may not recover costs incurred to
construct generating plants that are canceled.
(Applies to each
registrant)
Our
business plan for the construction of new generating units involves a number of
risks, including construction delays, nonperformance by equipment suppliers, and
increases in equipment and labor costs. To limit the risks of these construction
projects, we enter into equipment purchase orders and construction contracts and
incur engineering and design service costs in advance of receiving necessary
regulatory approvals and/or siting or environmental permits. If any of these
projects are cancelled for any reason, including our failure to receive
necessary regulatory approvals and/or siting or environmental permits, we could
incur significant cancellation penalties under the equipment purchase orders and
construction contracts. In addition, we may need to impair any construction
work-in process assets for any expenses we have incurred.
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:
·
|
the
potential harmful effects on the environment and human health resulting
from the operation of nuclear facilities and the storage, handling and
disposal of radioactive materials such as spent nuclear
fuel;
|
·
|
limitations
on the amounts and types of insurance commercially available to cover
losses that might arise in connection with our nuclear
operations;
|
·
|
uncertainties
with respect to contingencies and assessment amounts if insurance coverage
is inadequate (federal law requires owners of nuclear units to purchase
the maximum available amount of nuclear liability insurance and
potentially contribute to the losses of others);
and,
|
·
|
uncertainties
with respect to the technological and financial aspects of decommissioning
nuclear plants at the end of their licensed
lives.
|
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 any 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. The rules
governing the various regional power markets, including SPP and PJM, may also
change from time to time which could affect our costs or
revenues. Because the manner in which RTOs will evolve remains
unclear, we are unable to assess fully the impact that changes in these power
markets may have on our business.
The amount we charged third parties
for using our transmission facilities has been reduced and is subject to
refund.
(
Applies to AEP, APCo, CSPCo, I&M
and OPCo.)
In July
2003, the FERC issued an order directing PJM and 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
reduced the transmission service revenues collected by the RTOs and thereby
reduced 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. Because intervenors objected to this decision, the SECA fees we
collected ($220 million) are subject to refund.
A hearing
was held in May 2006 to determine whether any of the SECA revenues should be
refunded. In August 2006, the ALJ ruled that the rate design for the recovery of
SECA charges was flawed and that a large portion was 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, it would disallow $90 million of the AEP East companies’ remaining $115
million of unsettled gross SECA revenues. We have recorded provisions
in the aggregate amount of $37 million related to the potential refund of SECA
rates. After completed and in-process settlements, the AEP East companies will
have a remaining reserve balance of $35 million to settle the remaining
unsettled gross SECA revenues.
An increase in the amount PJM charges
us for transmitting power over its network may not be fully
recoverable.
(Applies to AEP and
I&M.)
On June
1, 2007, in response to a 2006 FERC order, PJM revised its methodology for
calculating the effect of transmission line losses in generation dispatch when
determining locational marginal prices. The new method is
designed to recognize the varying delivery costs of transmitting electricity
from individual generator locations to the places where customers consume the
energy. Due to the implementation of the new methodology, we
experienced an increase in the cost of transmitting energy to customer load
zones in the PJM. AEP has initiated discussions with PJM regarding
the impact of the new methodology and will pursue a modification through the
appropriate stakeholder processes. Management believes these
additional costs should be recoverable through retail and/or cost-based
wholesale rates. Recovery has been authorized by the PUCO and
VSCC. The filing with the IURC is pending and filings in other
affected jurisdictions are planned. In the interim, such costs in these
jurisdictions will have an adverse effect on future results of operations and
cash flows. Management is unable to predict whether full recovery
will ultimately be approved.
We could be subject to higher costs
and/or penalties related to mandatory reliability standards.
(Applies to each
registrant.)
As a
result of EPACT, owners and operators of the bulk power transmission system are
subject to mandatory reliability standards promulgated by the North American
Electric Reliability Corporation and enforced by the FERC. These standards,
which previously were being applied on a voluntary basis, became mandatory in
June 2007. The standards are based on the functions that need to be performed to
ensure the bulk power system operates reliably and is guided by reliability and
market interface principles. Compliance with new reliability standards may
subject us to higher operating costs and/or increased capital expenditures.
While we expect to recover costs and expenditures from customers through
regulated rates, there can be no assurance that the applicable commissions will
approve full recovery in a timely manner. If we were found not to be
in compliance with the mandatory reliability standards, we could be subject to
sanctions, including substantial monetary penalties, which likely would not be
recoverable from customers through regulated rates.
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. 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. Developments in federal legislative and regulatory
initiatives (which have occurred over the past few years and which have
generally facilitated competition in the energy sector) and/or (2) state
regulation could cause the regulatory environment to 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.)
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. 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.)
Since the
bankruptcy of Enron, the credit ratings agencies have periodically reviewed our
capital structure and the quality and stability of our earnings. Any
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
securities 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. In
February 2008, Fitch downgraded the senior unsecured debt rating of PSO to BBB+
with stable outlook. Moody’s placed the senior unsecured debt rating
of APCo, OPCo, SWEPCo and TCC on negative outlook in January
2008. Moody’s assigns the following ratings to the senior unsecured
debt of these companies: APCo Baa2, OPCo A3, SWEPCo Baa1 and TCC
Baa2.
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, 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 Ohio, we have limited ability to
pass on our fuel costs to our customers.
(Applies to AEP, CSPCo
and OPCo.)
Because
generation is no longer regulated in Ohio, we are exposed to risk from changes
in the market prices of coal, natural gas, and emissions allowances used to
generate power. The prices of coal, natural gas and emissions
allowances have increased materially in the recent past. The
protection afforded by retail fuel clause recovery mechanisms has been
eliminated by the implementation of customer choice in Ohio, which represents
approximately 20% of our fuel costs. As long as generating costs
cannot be passed through to customers as a matter of right in Ohio, we retain
these risks. If we cannot recover an amount sufficient to cover our
actual fuel costs, our results of operations and cash flows would be adversely
affected.
Downgrades in the credit ratings of
companies insuring certain of our financings could cause our costs of borrowing
to increase for the foreseeable future.
(Applies to each
registrant.)
A
significant amount of our financings involve the periodic resetting of the
interest rates applicable in those financings pursuant to auctions among
investors (“Auction Rate Bonds”). In order to attract additional
investors to these auctions, we often procure financial guaranty policies that
insure our obligation to pay interest and principal on our Auction Rate
Bonds. Credit downgrades and financial difficulties of certain
providers of financial guaranty policies have significantly reduced investor
willingness to place bids on Auction Rate Bonds. These events have caused the
interest rates on Auction Rate Bonds to increase, thereby increasing our cost of
capital and diminishing our earnings. While we may seek to
limit the impact of these increased costs by attempting to refinance our Auction
Rate Bonds, there can be no assurance as to our ability to do so at attractive
rates.
Risks
Relating to State Restructuring
In Ohio, our future rates are
uncertain.
(Applies to
AEP, OPCo and CSPCo.)
CSPCo and
OPCo are involved in discussions with various stakeholders in Ohio about
potential legislation to address the period following the expiration of the RSPs
on December 31, 2008. In August 2007, legislation was introduced that
would significantly reduce the likelihood of CSPCo’s and OPCo’s ability to
charge market-based rates for generation at the expiration of their
RSPs. The legislation has been passed by the Ohio Senate and still
must be considered by the Ohio House of Representatives. At this time,
management is unable to predict whether CSPCo and OPCo will transition to market
pricing, extend their RSP rates, with or without modification, or become subject
to a legislative reinstatement of some form of cost-based regulation for their
generation supply business on January 1, 2009. A return to cost-based
rates for generation supply in Ohio could have an adverse impact on our
financial condition, future results of operations and cash
flows. Further, the return of cost-based regulation could cause the
generation business of CSPCo and OPCo to meet the criteria for application of
regulatory accounting principles. Results of operations and financial condition
could be adversely affected if and when CSPCo and OPCo are required to
re-establish certain net regulatory liabilities applicable to their generation
supply business.
There is uncertainty as to our
recovery of stranded costs resulting from industry restructuring in
Texas.
(Applies to
AEP.)
Restructuring
legislation in Texas required utilities with stranded costs to use market-based
methods to value certain generating assets for determining stranded
costs. We elected to use the sale of assets method to determine the
market value of TCC’s generation assets for stranded cost
purposes. In general terms, the amount of stranded costs under this
market valuation methodology is the amount by which the book value of generating
assets, including regulatory assets and liabilities that were not securitized,
exceeds the market value of the generation assets, as measured by the net
proceeds from the sale of the assets. In May 2005, TCC filed its stranded cost
quantification application 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. We have appealed the PUCT’s
final order seeking additional recovery consistent with the Texas Restructuring
Legislation and related rules, other parties have appealed the PUCT’s final
order as unwarranted or too large. Management cannot predict the ultimate
outcome of any future court appeals or any future remanded PUCT
proceeding.
Collection of our revenues in Texas
is concentrated in a limited number of REPs.
(Applies to
AEP.)
Our
revenues from the distribution of electricity in the ERCOT area of Texas are
collected from REPs that supply the electricity we distribute to their
customers. Currently, we do business with approximately seventy
REPs. In 2007, TCC’s largest customer accounted for 23% of its
operating revenues; TNC’s largest customer (a non-utility affiliate) accounted
for 35% of its operating revenues and its second largest customer accounted for
15% of its operating revenues. Adverse economic conditions,
structural problems in the Texas market or financial difficulties of one or more
REPs could impair the ability of these REPs to pay for our services or could
cause them to delay such payments. We depend on these REPs for timely
remittance of payments. Any delay or default in payment could
adversely affect the timing and receipt of our cash flows and thereby have an
adverse effect on our liquidity.
Risks
Related to Owning and Operating Generation Assets and Selling Power
Our costs of compliance with
environmental laws are significant and the cost of compliance with future
environmental laws could harm our cash flow and profitability or cause some of
our electric generating units to be uneconomical to maintain or
operate.
(
Applies to each
registrant
.)
Our
operations are subject to extensive federal, state and local environmental
statutes, rules and regulations relating to air quality, water quality, waste
management, natural resources and health and safety. Compliance with
these legal requirements requires us to commit significant capital toward
environmental monitoring, installation of pollution control equipment, emission
fees and permits at all of our facilities. These expenditures have
been significant in the past, and we expect that they will increase in the
future. Further, environmental advocacy groups, other organizations
and some agencies in the United States are focusing considerable attention on
CO
2
emissions from power generation facilities and their potential role in climate
change. Although several bills have been introduced in Congress that
would compel CO
2
emission
reductions, none have advanced through the legislature. On April 2,
2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has
authority to regulate emissions of CO
2
and other
greenhouse gases under the CAA. Costs of compliance with
environmental regulations could adversely affect our results of operations and
financial position, especially if emission and/or discharge limits are
tightened, more extensive permitting requirements are imposed, additional
substances become regulated and the number and types of assets we operate
increase. All of our estimates are subject to significant
uncertainties about the outcome of several interrelated assumptions and
variables, including timing of implementation, required levels of reductions,
allocation requirements of the new rules and our selected compliance
alternatives. As a result, we cannot estimate our compliance costs
with certainty. The actual costs to comply could differ significantly
from our estimates. All of the costs are incremental to our current
investment base and operating cost structure. In addition, any legal
obligation that would require us to substantially reduce our emissions beyond
present levels could require extensive mitigation efforts and, in the case of
CO
2
legislation, would raise uncertainty about the future viability of fossil fuels,
particularly coal, as an energy source for new and existing electric generation
facilities. While we expect to recover our expenditures for pollution
control technologies, replacement generation and associated operating costs from
customers through regulated rates (in regulated jurisdictions) or market prices
(in Ohio and Texas), without such recovery those costs could adversely affect
future results of operations and cash flows, and possibly financial
condition.
Governmental authorities may assess
penalties on us if it is determined that we have not complied with environmental
laws and regulations.
(
Applies to each
registrant
.)
If we
fail to comply with environmental laws and regulations, even if caused by
factors beyond our control, that failure may result in the assessment of civil
or criminal penalties and fines against us. In July 2004 attorneys
general of eight states and others sued AEP and other utilities alleging that
CO
2
emissions from power generating facilities constitute a public nuisance under
federal common law. The trial court dismissed the suits and
plaintiffs have appealed the dismissal. While we believe the claims
are without merit, the costs associated with reducing CO
2
emissions
could harm our business and our results of operations and financial
position.
If these
or other future actions are resolved against us, substantial modifications of
our existing coal-fired power plants could be required. In addition,
we could be required to invest significantly in additional emission control
equipment, accelerate the timing of capital expenditures, pay penalties and/or
halt operations. Moreover, our results of operations and financial
position could be reduced due to the timing of recovery of these investments and
the expense of ongoing litigation.
Our revenues and results of
operations from selling power are subject to market risks that are beyond our
control.
(Applies to each
registrant.)
We sell
power from our generation facilities into the spot market or other competitive
power markets or on a contractual basis. We also enter into contracts
to purchase and sell electricity, natural gas, emission allowances and coal as
part of our power marketing and energy trading operations. With
respect to such transactions, we are generally not guaranteed any rate of return
on our capital investments through mandated rates, and our revenues and results
of operations are likely to depend, in large part, upon prevailing market prices
for power in our regional markets and other competitive
markets. These market prices may fluctuate substantially over
relatively short periods of time. Trading margins may erode as
markets mature and there may be diminished opportunities for gain should
volatility decline. In addition, the FERC, which has jurisdiction
over wholesale power rates, as well as RTOs that oversee some of these markets,
may impose price limitations, bidding rules and other mechanisms to address some
of the volatility in these markets. Power supply and other similar
agreements entered into during extreme market conditions may subsequently be
held to be unenforceable by a reviewing court or the FERC. Fuel and
emissions prices may also be volatile, and the price we can obtain for power
sales may not change at the same rate as changes in fuel and/or emissions
costs. These factors could reduce our margins and therefore diminish
our revenues and results of operations.
Volatility
in market prices for fuel and power may result from:
·
|
transmission
or transportation constraints or
inefficiencies;
|
·
|
availability
of competitively priced alternative energy
sources;
|
·
|
demand
for energy commodities;
|
·
|
natural
gas, crude oil and refined products, and coal production
levels;
|
·
|
natural
disasters, wars, embargoes and other catastrophic events;
and
|
·
|
federal,
state and foreign energy and environmental regulation and
legislation.
|
Our power trading (including coal,
gas and e
mission
allowances trading
and
power marketing) and risk management policies cannot eliminate the risk
associated with these activities.
(Applies to each
registrant.)
Our power
trading (including coal, gas and emission allowances trading and power
marketing) activities expose us to risks of commodity price
movements. We attempt to manage our exposure by establishing and
enforcing risk limits and risk management procedures. These risk
limits and risk management procedures may not work as planned and cannot
eliminate the risks associated with these activities. As a result, we
cannot predict the impact that our energy trading and risk management decisions
may have on our business, operating results or financial position.
We
routinely have open trading positions in the market, within guidelines we set,
resulting from the management of our trading portfolio. To the extent
open trading positions exist, fluctuating commodity prices can improve or
diminish our financial results and financial position.
Our power
trading and risk management activities, including our power sales agreements
with counterparties, rely on projections that depend heavily on judgments and
assumptions by management of factors such as the future market prices and demand
for power and other energy-related commodities. These factors become
more difficult to predict and the calculations become less reliable the further
into the future these estimates are made. Even when our policies and
procedures are followed and decisions are made based on these estimates, results
of operations may be diminished if the judgments and assumptions underlying
those calculations prove to be inaccurate.
Our financial performance may be
adversely affected if we are unable to operate our pooled electric generating
facilities successfully.
(Applies to each
registrant.)
Our
performance is highly dependent on the successful operation of our electric
generating facilities. Operating electric generating facilities
involves many risks, including:
·
|
operator
error and breakdown or failure of equipment or
processes;
|
·
|
operating
limitations that may be imposed by environmental or other regulatory
requirements;
|
·
|
fuel
supply interruptions caused by transportation constraints, adverse
weather, non-performance by our suppliers and other factors;
and
|
·
|
catastrophic
events such as fires, earthquakes, explosions, hurricanes, terrorism,
floods or other similar
occurrences.
|
A
decrease or elimination of revenues from power produced by our electric
generating facilities or an increase in the cost of operating the facilities
would adversely affect our results of operations.
Parties with whom we have contracts
may fail to perform their obligations, which could harm our results of
operations.
(Applies to each
registrant.)
We are
exposed to the risk that counterparties that owe us money or power could breach
their obligations. Should the counterparties to these arrangements
fail to perform, we may be forced to enter into alternative hedging arrangements
or honor underlying commitments at then-current market prices that may exceed
our contractual prices, which would cause our financial results to be diminished
and we might incur losses. Although our estimates take into account the expected
probability of default by a counterparty, our actual exposure to a default by a
counterparty may be greater than the estimates predict.
We rely on electric transmission
facilities that we do not own or control. If these facilities do not
provide us with adequate transmission capacity, we may not be able to deliver
our wholesale electric power to the purchasers of our power.
(Applies to each
registrant.)
We depend
on transmission facilities owned and operated by other unaffiliated power
companies to deliver the power we sell at wholesale. This dependence
exposes us to a variety of risks. If transmission is disrupted, or
transmission capacity is inadequate, we may not be able to sell and deliver our
wholesale power. If a region’s power transmission infrastructure is
inadequate, our recovery of wholesale costs and profits may be
limited. If restrictive transmission price regulation is imposed, the
transmission companies may not have sufficient incentive to invest in expansion
of transmission infrastructure.
The FERC
has issued electric transmission initiatives that require electric transmission
services to be offered unbundled from commodity sales. Although these
initiatives are designed to encourage wholesale market transactions for
electricity and gas, access to transmission systems may in fact not be available
if transmission capacity is insufficient because of physical constraints or
because it is contractually unavailable. We also cannot predict
whether transmission facilities will be expanded in specific markets to
accommodate competitive access to those markets.
We do not fully hedge against price
changes in commodities.
(Applies to each
registrant.)
We
routinely enter into contracts to purchase and sell electricity, natural gas,
coal and emission allowances as part of our power marketing and energy and
emission allowances trading operations. In connection with these
trading activities, we routinely enter into financial contracts, including
futures and options, over-the counter options, financially-settled swaps and
other derivative contracts. These activities expose us to risks from
price movements. If the values of the financial contracts change in a
manner we do not anticipate, it could harm our financial position or reduce the
financial contribution of our trading operations.
We manage
our exposure by establishing risk limits and entering into contracts to offset
some of our positions (i.e., to hedge our exposure to demand, market effects of
weather and other changes in commodity prices). However, we do not
always hedge the entire exposure of our operations from commodity price
volatility. To the extent we do not hedge against commodity price
volatility, our results of operations and financial position may be improved or
diminished based upon our success in the market.
ITEM
2. PROPERTIES
GENERATION
FACILITIES
UTILITY
OPERATIONS
At
December 31, 2007, the AEP System owned (or leased where indicated) generating
plants with net power capabilities (winter rating) shown in the following
table:
Company
|
Stations
|
|
Coal
MW
|
|
Natural
Gas
MW
|
|
Nuclear
MW
|
|
Lignite
MW
|
|
Hydro
MW
|
|
Oil
MW
|
|
Total
MW
|
AEGCo
|
2
|
(a)
|
|
1,300
|
|
1,146
|
|
|
|
|
|
|
|
|
|
2,446
|
APCo
|
17
|
(b)(c)
|
|
5,093
|
|
523
|
|
|
|
|
|
681
|
|
|
|
6,297
|
CSPCo
|
7
|
(d)
|
|
2,345
|
|
1,357
|
|
|
|
|
|
|
|
|
|
3,702
|
I&M
|
9
|
(a)
|
|
2,295
|
|
|
|
2,191
|
|
|
|
15
|
|
|
|
4,501
|
KPCo
|
1
|
|
|
1,060
|
|
|
|
|
|
|
|
|
|
|
|
1,060
|
OPCo
|
8
|
(b)(c)(e)
|
|
8,472
|
|
|
|
|
|
|
|
26
|
|
|
|
8,498
|
PSO
|
8
|
(f)
|
|
1,018
|
|
3,238
|
|
|
|
|
|
|
|
25
|
|
4,281
|
SWEPCo
|
10
|
(g)
|
|
1,848
|
|
2,167
|
|
|
|
842
|
|
|
|
|
|
4,857
|
TNC
|
11
|
(f)
(h)
|
|
377
|
|
1,014
|
|
|
|
|
|
|
|
8
|
|
1,399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
System
Totals
|
67
|
|
|
23,808
|
|
9,445
|
|
2,191
|
|
842
|
|
722
|
|
33
|
|
37,041
|
Percentage
of System Totals
|
|
|
|
64.3%
|
|
25.5%
|
|
5.9%
|
|
2.3%
|
|
1.9%
|
|
0.1%
|
|
|
(a)
|
Unit
1 of the Rockport Plant is owned one-half by AEGCo and one-half by
I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and
one-half by I&M. The leases terminate in 2022 unless extended. In May
2007, AEGCo completed the purchase of the Lawrenceburg Plant, a 1,146 MW
gas-fired unit (winter rating) in Indiana from Public Service Electric and
Gas Company. In September 2007, AEGCo purchased the
Dresden Generating station, a gas-fired unit in Ohio currently under
construction. Upon completion, which is expected to be in 2009
or 2010, this unit will be a 580 MW
facility.
|
(b)
|
Unit
3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by
OPCo.
|
(c)
|
APCo
owns Units 1 and 3 and OPCo owns Units 2, 4 and 5 of Philip Sporn Plant,
respectively.
|
(d)
|
CSPCo
owns generating units in common with Duke Ohio and DP&L. Its
percentage ownership interest is reflected in this table. In April 2007,
CSPCo completed the purchase of the Darby Electric Generating station, a
507 MW gas-fired unit (winter rating) in Ohio from
DP&L.
|
(e)
|
The
scrubber facilities at the General James M. Gavin Plant are
leased. OPCo is permitted to terminate the lease as early as
2010.
|
(f)
|
As
of December 31, 2007, PSO and TNC, along with Oklahoma Municipal Power
Authority and The Public Utilities Board of the City of Brownsville,
Texas, jointly owned the Oklaunion power station. PSO’s ownership interest
is reflected in this portion of the table. In February 2007, TCC sold its
interest in Oklaunion to The Public Utilities Board of the City of
Brownsville, Texas. In order to comply with the separation requirements of
the Texas Act, in January 2007, TNC entered into a 20-year purchase power
agreement transferring its generating capacity in the Oklaunion power
station to a non-utility affiliate.
|
(g)
|
SWEPCo
owns generating units in common with unaffiliated parties. Only its
ownership interest is reflected in this table. Also, SWEPCo began
commercial operation of Units 3 and 4, of 88 MW each, at its gas–fired
Mattison Plant in July 2007. Commercial operation of Units 1
and 2, of 85 MW each, at the Mattison Plant began in December
2007.
|
(h)
|
TNC’s
gas-fired and oil-fired generation has been
deactivated.
|
Cook
Nuclear Plant
The
following table provides operating information relating to the Cook
Plant.
|
Cook
Plant
|
|
Unit
1
|
|
Unit
2
|
Year
Placed in Operation
|
1975
|
|
1978
|
Year
of Expiration of NRC License
|
2034
|
|
2037
|
Nominal
Net Electrical Rating in Kilowatts
|
1,084,000
|
|
1,107,000
|
Net
Capacity Factors (a)
|
|
|
|
2007
|
97.4%
|
|
83.8%
|
2006
|
80.4%
|
|
86.5%
|
2005
|
88.8%
|
|
97.1%
|
2004
|
97.0%
|
|
81.6%
|
(a)
|
Net
Capacity Factor values for Unit 1 in 2007 reflect Nominal Net Electrical
Rating in Kilowatts of 1,084,000. The Net Capacity Factor
values for Unit 1 from 2004 through 2006 reflect the previous Nominal Net
Electrical Rating in Kilowatts of 1,036,000. The Net Electrical
Rating changed due to low pressure turbine
replacement.
|
Costs
associated with the operation (including fuel), maintenance and retirement of
nuclear plants continue to be more significant and less predictable than costs
associated with other sources of generation, in large part due to changing
regulatory requirements and safety standards, availability of nuclear waste
disposal facilities and experience gained in the operation of nuclear
facilities. However the ability of I&M to obtain adequate and timely
recovery of costs associated with the Cook Plant is not
assured. Such costs may include replacement power, any unamortized
investment at the end of the useful life of the Cook Plant (whether scheduled or
premature), the carrying costs of that investment and retirement
costs.
GENERATION
AND MARKETING
In
addition to the generating facilities described above, AEP has ownership
interests in other electrical generating facilities. Information concerning
these facilities at December 31, 2007 is listed below.
Facility
|
Fuel
|
Location
|
Capacity
Total
MW
|
Owner-ship
Interest
|
|
Status
|
|
|
|
|
|
|
|
Desert
Sky Wind Farm
|
Wind
|
Texas
|
161
|
100%
|
|
Exempt
Wholesale Generator(a)
|
|
|
|
|
|
|
|
Trent
Wind Farm
|
Wind
|
Texas
|
150
|
100%
|
|
Exempt
Wholesale Generator(a)
|
Total
(b)
|
|
311
|
|
|
|
(a) As defined under rules issued pursuant to
EPACT.
(b)
|
Does
not include (i) 50% interest in Sweeny, which was sold in October 2007, or
(ii) 377 MW of coal-fired generating capacity (representing TNC’s interest
in Oklaunion power station) which TNC has sold under a 20-year purchase
power agreement to a non-utility affiliate in the Generation and Marketing
business segment.
|
See
Note 8 to the consolidated financial statements entitled
Acquisitions, Dispositions,
Discontinued Operations, Impairments and Assets Held for Sale,
included
in the 2007 Annual Reports, for a discussion of AEP’s disposition of independent
power producer and foreign generation assets.
TRANSMISSION AND
DISTRIBUTION FACILITIES
The
following table sets forth the total overhead circuit miles of transmission and
distribution lines of the AEP System and its operating companies and that
portion of the total representing 765kV lines:
|
Total
Overhead Circuit Miles of Transmission and Distribution
Lines
|
|
Circuit
Miles of
765kV
Lines
|
AEP
System (a)
|
223,814
|
(b)
|
|
2,116
|
|
APCo
|
51,833
|
|
|
734
|
|
CSPCo
(a)
|
15,476
|
|
|
|
|
I&M
|
22,036
|
|
|
615
|
|
Kingsport
Power Company
|
1,358
|
|
|
|
|
KPCo
|
10,959
|
|
|
258
|
|
OPCo
|
30,763
|
|
|
509
|
|
PSO
|
21,172
|
|
|
—
|
|
SWEPCo
|
21,389
|
|
|
—
|
|
TCC
|
29,650
|
|
|
—
|
|
TNC
|
17,475
|
|
|
—
|
|
WPCo
|
1,703
|
|
|
—
|
|
(a)
|
Includes
766 miles of 345,000-volt jointly owned
lines.
|
(b)
|
Includes
73 miles of overhead transmission lines not identified with an operating
company.
|
TITLES
The AEP
System’s generating facilities are generally located on lands owned in fee
simple. The greater portion of the transmission and distribution lines of the
System has been constructed over lands of private owners pursuant to easements
or along public highways and streets pursuant to appropriate statutory
authority. The rights of AEP’s public utility subsidiaries in the realty on
which their facilities are located are considered adequate for use in the
conduct of their business. Minor defects and irregularities customarily found in
title to properties of like size and character may exist, but such defects and
irregularities do not materially impair the use of the properties affected
thereby. AEP’s public utility subsidiaries generally have the right of eminent
domain which permits them, if necessary, to acquire, perfect or secure titles to
or easements on privately held lands used or to be used in their utility
operations. Recent legislation in Ohio and Virginia has restricted
the right of eminent domain previously granted for power generation
purposes.
SYSTEM TRANSMISSION LINES
AND FACILITY SITING
Laws in
the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Texas,
Tennessee, Virginia, and West Virginia require prior approval of sites of
generating facilities and/or routes of high-voltage transmission lines. We have
experienced delays and additional costs in constructing facilities as a result
of proceedings conducted pursuant to such statutes, and in proceedings in which
our operating companies have sought to acquire rights-of-way through
condemnation. These proceedings may result in additional delays and
costs in future years. See
Management’s Financial Discussion
and Analysis of Results of Operations
included in the 2007 Annual
Reports, for more information on current siting proceedings.
CONSTRUCTION
PROGRAM
GENERAL
With
input from its state utility commissions, the AEP System continuously assesses
the adequacy of its generation, transmission, distribution and other facilities
to plan and provide for the reliable supply of electric power and energy to its
customers. In this assessment process, assumptions are continually being
reviewed as new information becomes available, and assessments and plans are
modified, as appropriate. AEP forecasts $3.8 billion, $3.7 billion
and $3.6 billion of construction expenditures, excluding AFUDC, for 2008, 2009
and 2010, respectively. Estimated construction expenditures are
subject to periodic review and modification and may vary based on the ongoing
effects of regulatory constraints, environmental regulations, business
opportunities, market volatility, economic trends, and the ability to access
capital.
PROPOSED
TRANSMISSION FACILITIES
Joint
Venture
in
PJM
In June
2007 PJM authorized the construction of a major new transmission line to address
the reliability and efficiency needs of the PJM system. PJM has
identified a need for a new line to be ready as early as 2012. The
line would be 765kV for most of its length and would run approximately 290 miles
from APCo’s Amos substation in West Virginia to Allegheny Energy Inc.’s (“AYE”)
proposed Kemptown station in north central Maryland. In September
2007, AEP and AYE entered into a joint venture to construct, own and operate
transmission facilities in the PJM region, including the Amos-to-Kemptown
transmission line. In December 2007 the joint venture filed an application with
the FERC for approval of a return on equity and formula rate for the
Amos-to-Kemptown transmission line. In addition to the rate recovery
sought through the FERC, the joint venture will seek appropriate regulatory
approvals from the appropriate state utility commissions. The total cost of the
Amos-to-Kemptown line is estimated to be approximately $1.8 billion, and AEP’s
estimated share will be approximately $600 million. The joint venture
will not be consolidated with AEP for financial or tax reporting
purposes. See
Management’s Financial Discussion
and Analysis of Results of Operations
included in the 2007 Annual
Reports, for more information.
Joint
Venture in ERCOT
In January 2007, TCC entered into an
agreement to establish a joint venture with MidAmerican Energy Holdings Company
(“MidAmerican”) to fund, own and operate electric transmission assets in
ERCOT. In January 2007, a filing was made with the PUCT seeking
regulatory approval to operate as an electric transmission utility in Texas, to
transfer from TCC to the joint venture transmission assets and to establish a
wholesale transmission tariff. In December 2007, the PUCT issued an
order on rehearing approving the transaction and initial tariffs; AEP and
MidAmerican then closed the formation transactions. Subsidiaries of AEP and
MidAmerican each hold a 50 percent equity interest in the joint
venture. The joint venture will not be consolidated with AEP for
financial or tax reporting purposes. See
Management’s Financial Discussion
and Analysis of Results of Operations
and Note 8 to the consolidated
financial statements, entitled
Acquisitions, Dispositions,
Discontinued Operations, Impairments and Assets Held for Sale
, included
in the 2007 Annual Reports, for more information.
PROPOSED
GENERATION FACILITIES
IGCC
Projects
An independent committee of AEP’s Board
of Directors issued a landmark report in August 2004 called
An Assessment of AEP’s Actions to
Mitigate the Economic Impacts of Emissions
Policies, the first of its
kind in the United States. It evaluated the economic risks to the
company posed by emissions policies. In conjunction with this report,
we announced plans to construct a synthesis-gas-fired plant or plants for a
total of approximately 1,200 MW of capacity in the next five to six years
utilizing integrated gasification combined cycle (IGCC)
technology. These plans are contingent upon receiving adequate cost
recovery through rates approved by the applicable commission before beginning
construction.
Ohio
IGCC Plant
In March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. In June 2006, the PUCO issued an order
approving a tariff to recover pre-construction costs, subject to
refund. In August 2006, intervenors filed four separate appeals of
the PUCO’s order in the IGCC proceeding and this is being litigated before the
Ohio Supreme Court. Pending the outcome of the litigation, CSPCo and
OPCo announced they would delay the start of construction of the IGCC
plant. Recent estimates of the cost to build this plant have
escalated to $2.7 billion, based on an in service date of 2017. See
Management’s Financial
Discussion and Analysis of Results of Operations
and Note 4 to the
consolidated financial statements, entitled
Rate Matters
, included in the
2007 Annual Reports, for more information.
West
Virginia IGCC
In
January 2006, APCo filed a petition with the WVPSC requesting its approval of a
Certificate of Public Convenience and Necessity (CCN) to construct a proposed
629 MW IGCC plant. The plant is to be built adjacent to APCo’s
existing Mountaineer Generating Station in Mason County, WV for an estimated
cost of $2.2 billion. In June 2007, APCo filed a request with the
Virginia SCC for a rate adjustment clause to recover a return on the
plant. Neither filing has yet been approved. See
Management’s Financial Discussion
and Analysis of Results of Operations
and Note 4 to the consolidated
financial statements, entitled
Rate Matters
, included in the
2007 Annual Reports, for more information.
SWEPCo
Projects
In May
2006, SWEPCo announced plans to construct new peaking and intermediate
generation facilities that would be operational in 2008 and
2010. Commercial operation of Units 3 and 4 at the gas–fired Mattison
Plant began in July 2007, while Units 1 and 2 began commercial operation in
December 2007. In 2008, SWEPCo anticipates commencing construction of
a 480 MW combined-cycle natural gas fired plant at its existing Arsenal Hill
Power Plant in Shreveport, Louisiana (the “Stall Unit”). Filings have
been made with the PUCT, APSC and the LPSC seeking approvals to construct the
Stall Unit. The Stall Unit is estimated to cost $378 million,
excluding AFUDC, and is expected to be operational in mid-2010. See
Note 4 to the consolidated financial statements, entitled
Rate Matters
, included in the
2007 Annual Reports, for more information.
In August
2006, SWEPCo announced plans to build a new base load 600 MW pulverized coal
ultra-supercritical generating unit in Arkansas named the John W. Turk, Jr.
Power Plant (the “Turk Plant”). SWEPCo submitted filings with the
APSC, PUCT and LPSC seeking approvals to proceed with the Turk
Plant. SWEPCo anticipates owning 73% of the Turk Plant and will be
the operator. During 2007, SWEPCO signed joint ownership,
construction and operations agreements with Oklahoma Municipal Power Authority,
Arkansas Electric Cooperative Corporation and East Texas Electric Cooperative
for the remaining 27% of the Turk Plant. The Turk Plant is estimated
to cost $1.3 billion with SWEPCo’s 73% portion estimated to cost $950 million,
excluding AFUDC. If approved on a timely basis, the Turk Plant is
expected to be operational in 2012. In November 2007, the APSC
approved construction of the plant. The remaining applications for
approval are pending. See Note 4 to the consolidated financial
statements, entitled
Rate
Matters
, included in the 2007 Annual Reports, for more
information.
PSO
Projects
Pursuant
to plans announced in March 2006, in 2007 PSO commenced construction of 170 MWs
of peaking generation, comprised of two 85 MW simple-cycle natural gas
combustion turbines, at each of its existing generation facilities in Jenks,
Oklahoma (Riverside Station) and Anadarko, Oklahoma (Southwestern
Station). The peaking facilities are expected to be completed in 2008
at an aggregate cost of approximately $117 million and have been approved by the
Oklahoma Corporation Commission (“OCC”). In October, 2007 the OCC
denied PSO’s and Oklahoma Gas and Electric Company’s (“OG&E”) request for
pre-approval of a new 950 MW coal-fueled electricity generating unit near Red
Rock, Oklahoma. The joint venture between PSO and OG&E to
construct the plant was subsequently terminated. See Note 4 to the consolidated
financial statements, entitled
Rate Matters
, included in the
2007 Annual Reports, for more information.
Other
Our
significant planned environmental investments in emission control installations
at existing coal-fired plants and our commitment to IGCC and ultra-supercritical
technology reinforce our belief that coal will be a lower-emission domestic
energy source of the future and further signals our commitment to invest in
clean, environmentally safe technology. For additional
information regarding anticipated environmental expenditures, see
Management’s Financial Discussion
and Analysis of Results of Operations
under the heading entitled
Environmental
Matters
.
CONSTRUCTION
EXPENDITURES
The
following table shows construction expenditures (including environmental
expenditures) during 2005, 2006 and 2007 and current estimates of 2008, 2009 and
2010 construction expenditures, in each case excluding AFUDC, capitalized
interest and assets acquired under leases.
|
2005
Actual
|
2006
Actual
|
2007
Actual
|
2008
Estimate
|
2009
Estimate
|
2010
Estimate
|
|
(in
thousands)
|
Total
AEP System
(a)
|
$2,501,600
|
(b)
|
$3,522,100
|
(c)
|
$3,402,900
|
(d)
|
$3,829,700
|
|
$3,749,900
|
$3,599,600
|
APCo
|
634,000
|
|
922,700
|
|
712,000
|
|
726,100
|
|
753,200
|
628,600
|
CSPCo
|
171,600
|
|
315,100
|
|
330,200
|
|
404,200
|
|
351,000
|
329,800
|
I&M
|
317,100
|
|
306,900
|
|
282,400
|
|
385,700
|
|
440,200
|
380,300
|
OPCo
|
733,400
|
|
968,700
|
|
805,400
|
|
634,700
|
|
591,100
|
549,900
|
PSO
|
139,700
|
|
245,200
|
|
302,600
|
|
276,500
|
|
363,300
|
463,300
|
SWEPCo
|
151,200
|
|
330,300
|
|
510,600
|
|
741,000
|
|
620,000
|
637,600
|
(a)
|
Includes
expenditures of other subsidiaries not shown. The figures reflect
construction expenditures, not investments in subsidiary
companies. Excludes discontinued
operations.
|
(b)
|
Excludes
$293 million for the purchase of Ceredo (APCo) and Waterford (CSPCo)
generating plants and Cash Flow Statement Adjustments (Statement of Cash
Flow Including AFUDC Debt Equals
$2,403,800)
|
(c)
|
Excludes
Cash Flow Statement Adjustments (Statement of Cash Flow Including AFUDC
Debt Equals $3,528,000)
|
(d)
|
Excludes
$512 million for the purchase of Lawrenceburg, Dresden (AEGCo) and Darby
(CSPCo) and Cash Flow Statement Adjustments (Statement of Cash Flow
Including AFUDC Debt Equals
$3,556,000)
|
The
System construction program is reviewed continuously and is revised from time to
time in response to changes in estimates of customer demand, business and
economic conditions, the cost and availability of capital, environmental
requirements and other factors. Changes in construction schedules and costs, and
in estimates and projections of needs for additional facilities, as well as
variations from currently anticipated levels of net earnings, Federal income and
other taxes, and other factors affecting cash requirements, may increase or
decrease the estimated capital requirements for the System’s construction
program.
POTENTIAL UNINSURED
LOSSES
Some
potential losses or liabilities may not be insurable or the amount of insurance
carried may not be sufficient to meet potential losses and liabilities,
including liabilities relating to damage to our generating plants and costs of
replacement power. Unless allowed to be recovered through rates, future losses
or liabilities which are not completely insured could have a material adverse
effect on results of operations and the financial condition of AEP and other AEP
System companies. For risks related to owning a nuclear generating unit, see
Note 10 to the consolidated financial statements entitled
Nuclear
for information with
respect to nuclear incident liability insurance.