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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended SEPTEMBER 30, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from to
----- ----
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address of Principal Executive Offices, and Telephone Number Identification No.
- ----------- ------------------------------------------------------------ ------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) 13-4922640
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
0-346 AEP TEXAS CENTRAL COMPANY (A Texas Corporation) 74-0550600
0-340 AEP TEXAS NORTH COMPANY (A Texas Corporation) 75-0646790
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455
All Registrants 1 Riverside Plaza, Columbus, Ohio 43215-2373
Telephone (614) 716-1000
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to
file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes X No
----- ------
Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of
the Exchange Act).
Yes X No
----- ------
Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power
Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public
Service Company of Oklahoma and Southwestern Electric Power Company, are accelerated filers (as defined in Rule 12b-2 of the
Exchange Act).
Yes No X
----- ------
AEP Generating Company, AEP Texas North Company, Columbus Southern Power Company, Kentucky Power Company and Public Service
Company of Oklahoma meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing
this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.
Number of Shares
of Common Stock
Outstanding at Par Value at
October 29, 2004 October 29, 2004
---------------- ----------------
American Electric Power Company, Inc. 395,704,805 $6.50
AEP Generating Company 1,000 1,000
AEP Texas Central Company 2,211,678 25
AEP Texas North Company 5,488,560 25
Appalachian Power Company 13,499,500 -
Columbus Southern Power Company 16,410,426 -
Indiana Michigan Power Company 1,400,000 -
Kentucky Power Company 1,009,000 50
Ohio Power Company 27,952,473 -
Public Service Company of Oklahoma 9,013,000 15
Southwestern Electric Power Company 7,536,640 18
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2004
Glossary of Terms
Forward-Looking Information
Part I. FINANCIAL INFORMATION
Items 1, 2 and 3 - Financial Statements, Management's Financial Discussion
and Analysis and Quantitative and Qualitative Disclosures About Risk
Management Activities:
American Electric Power Company, Inc. and Subsidiary Companies:
Management's Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Consolidated Financial Statements
Notes to Consolidated Financial Statements
AEP Generating Company:
Management's Narrative Financial Discussion and Analysis
Financial Statements
AEP Texas Central Company and Subsidiary:
Management's Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Consolidated Financial Statements
AEP Texas North Company:
Management's Narrative Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Financial Statements
Appalachian Power Company and Subsidiaries:
Management's Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Consolidated Financial Statements
Columbus Southern Power Company and Subsidiaries:
Management's Narrative Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Consolidated Financial Statements
Indiana Michigan Power Company and Subsidiaries:
Management's Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Consolidated Financial Statements
Kentucky Power Company:
Management's Narrative Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Financial Statements
Ohio Power Company Consolidated:
Management's Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Consolidated Financial Statements
Public Service Company of Oklahoma:
Management's Narrative Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Financial Statements
Southwestern Electric Power Company Consolidated:
Management's Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Consolidated Financial Statements
Notes to Financial Statements of Registrant Subsidiaries
Registrant Subsidiaries' Combined Management's Discussion and Analysis
Item 4. Controls and Procedures
Part II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 5. Other Information
Item 6. Exhibits
Exhibits:
Exhibit 10
Exhibit 12
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
SIGNATURE
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, AEP Texas Central
Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information
contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no
representation as to information relating to the other registrants.
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Term Meaning
---- -------
AEGCo AEP Generating Company, an electric utility subsidiary of AEP.
AEP American Electric Power Company, Inc.
AEP Consolidated AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated domestic electric utility companies.
AEP East companies APCo, CSPCo, I&M, KPCo and OPCo.
AEPES AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEP System or the System The American Electric Power System, an integrated electric utility system, owned and operated
by AEP's electric utility subsidiaries.
AEPSC American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP System Power Pool or Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of
AEP Power Pool generation and resultant wholesale system sales of the member companies.
AEP West companies PSO, SWEPCo, TCC and TNC.
ALJ Administrative Law Judge.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
Cook Plant The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the
legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
DETM Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE United States Department of Energy.
ECAR East Central Area Reliability Council.
EITF The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT The Electric Reliability Council of Texas.
FASB Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
GAAP Generally Accepted Accounting Principles.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
IURC Indiana Utility Regulatory Commission.
JMG JMG Funding LP.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSC Kentucky Public Service Commission.
KWH Kilowatthour.
LIG Louisiana Intrastate Gas, an AEP subsidiary.
ME SWEPCo Mutual Energy SWEPCo L.P., a Texas retail electric provider.
Money Pool AEP System's Money Pool.
MTM Mark-to-Market.
MW Megawatt.
MWH Megawatthour.
NOx Nitrogen oxide.
OATT Open Access Transmission Tariff.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
PJM Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCT The Public Utility Commission of Texas.
PUHCA Public Utility Holding Company Act.
PURPA The Public Utility Regulatory Policies Act of 1978.
Registrant Subsidiaries AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC.
Risk Management Contracts Trading and non-trading derivatives, including those derivatives designated as cash flow and
fair value hedges.
Rockport Plant A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana
owned by AEGCo and I&M.
RTO Regional Transmission Organization.
SEC Securities and Exchange Commission.
SFAS Statement of Financial Accounting Standards issued by the Financial Accounting Standards
Board.
SFAS 133 Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities.
------------------------------------------------------------
SNF Spent Nuclear Fuel.
SPP Southwest Power Pool.
STP South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
AEP electric utility subsidiary.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC AEP Texas Central Company, an AEP electric utility subsidiary.
Tenor Maturity of a contract.
Texas Legislation Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding A filing to be made under the Texas Legislation to finalize the amount of stranded costs and
other true-up items and the recovery of such amounts.
TVA Tennessee Valley Authority.
VaR Value at Risk, a method to quantify risk exposure.
Virginia SCC Virginia State Corporation Commission.
Zimmer Plant William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.
FORWARD-LOOKING INFORMATION
This report made by AEP and certain of its subsidiaries contains forward-
looking statements within the meaning of Section 21E of the Securities Exchange
Act of 1934. Although AEP and each of its registrant subsidiaries believe that
their expectations are based on reasonable assumptions, any such statements
may be influenced by factors that could cause actual outcomes and results to
be materially different from those projected. Among the factors that could
cause actual results to differ materially from those in the forward-looking
statements are:
o Electric load and customer growth.
o Weather conditions, including storms.
o Available sources and costs of, and transportation for, fuels and the
creditworthiness of fuel suppliers and transporters.
o Availability of generating capacity and the performance of AEP's generating
plants.
o The ability to recover regulatory assets and stranded costs in
connection with deregulation.
o The ability to recover increases in fuel and other energy costs through
regulated or competitive electric rates.
o New legislation, litigation and government regulation including
requirements for reduced emissions of sulfur, nitrogen, mercury,
carbon and other substances.
o Resolution of pending and future rate cases, negotiations and other
regulatory decisions (including rate or other recovery for new
investments and environmental compliance).
o Oversight and/or investigation of the energy sector or its participants.
o Resolution of litigation (including pending Clean Air Act enforcement
actions and disputes arising from the bankruptcy of Enron Corp.).
o AEP's ability to constrain its operation and maintenance costs.
o The success of disposing of investments that no longer match AEP's business
model.
o AEP's ability to sell assets at acceptable prices and on other acceptable
terms.
o International and country-specific developments affecting foreign
investments including the disposition of any foreign investments.
o The economic climate and growth in AEP's service territory and changes in
market demand and demographic patterns.
o Inflationary trends.
o AEP's ability to develop and execute a strategy based on a view regarding
prices of electricity, natural gas, and other energy-related commodities.
o Changes in the creditworthiness and number of participants in the energy
trading market.
o Changes in the financial markets, particularly those affecting the
availability of capital and AEP's ability to refinance existing debt at
attractive rates.
o Actions of rating agencies, including changes in the ratings of debt and
preferred stock.
o Volatility and changes in markets for electricity, natural gas, and other
energy-related commodities.
o Changes in utility regulation, including membership and integration in a
regional transmission structure.
o Accounting pronouncements periodically issued by accounting standard-setting
bodies.
o The performance of AEP's pension and other postretirement benefit plans.
o Prices for power that AEP generates and sells at wholesale.
o Changes in technology and other risks and unforeseen events, including wars,
the effects of terrorism (including increased security costs), embargoes
and other catastrophic events.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
-----------------------------------------------------------------------
EXECUTIVE OVERVIEW
- ------------------
Utility Operations Segment Results
- ----------------------------------
While earnings from our Utility Operations were less than our earnings for the
same periods for the prior year, we are pleased with the results. Net income
from Utility Operations was $359 million for the third quarter 2004 and $845
million for the nine months ended September 30, 2004. We continue to see healthy
utility sales increases in most of our regions due to increased usage and growth
in our residential and commercial customer base for the first three quarters of
2004. Additionally, improvements in the economy are reflected in our industrial
sales. These favorable trends were not sufficient to offset the absence of the
Wholesale Capacity auction revenues in 2004, higher planned plant maintenance
and distribution system reliability improvement work, and the impact of
unfavorable weather in the third quarter due to a mild summer in 2004.
Progress Made on Asset Sales
- ----------------------------
We are on schedule with our planned divestiture of various unregulated
businesses and other assets and are making significant progress towards
completion of the disposal of our interests in AEP Texas Central Company (TCC)
generating assets. The proceeds from the sales are being used to reduce existing
long-term debt and other obligations. We expect the remaining asset sales to be
completed no later than mid 2005.
During the first six months of 2004, we completed (a) the sale of our interest
in the Pushan Power Plant in China, (b) the sale of Louisiana Intrastate Gas
Pipeline Company, and (c) the sale of the mining operations of AEP Coal.
During the third quarter 2004, we completed (a) the sale of two coal fired
plants in the U.K. (Fiddler's Ferry and Ferrybridge) along with related coal
inventory and a number of related commodity and freight contracts, (b) the sale
of our ownership interests in our two independent power producers in Florida and
one in Colorado, and (c) the sale of our 50 percent interest in South Coast
Power Limited, owner of the Shoreham Power Station in the U.K.
During October 2004, we completed (a) the sale of Jefferson Island Storage & Hub
LLC, including salt dome caverns and pipelines, (b) the sale of our ownership
interest in our final independent power producer in Colorado, and (c) the sale
of the former headquarters building for CSW in Dallas, Texas.
Unregulated assets that are currently being marketed include (a) our 50 percent
interest in Bajio, a 600 MW natural gas-fired generation facility located in
Mexico and (b) our 20 percent equity interest in Pacific Hydro, an Australian
renewable energy company. We will continue our effort to locate buyers for these
assets.
During the third quarter, we sold the majority of TCC's generation assets,
including eight natural gas plants, one coal-fired plant and one hydro plant.
The remaining TCC generation assets to be sold include TCC's share of the
Oklaunion Power Station and TCC's share of the South Texas Project (STP) nuclear
plant. Agreements have been reached for the sale of TCC's interest in both
facilities and we expect the sales to be completed in the first half of 2005.
Nevertheless, there could be potential delays in receiving necessary regulatory
approvals and clearances, which could delay the closings. The sale of the TCC
assets will allow us to determine stranded costs for recovery under the Texas
Legislation.
This year's sales of non-strategic, non-regulated international and domestic
assets are consistent with our strategy that focuses on our core domestic
utility business.
PJM Integration
- ---------------
We worked closely with regulators in all our states to successfully
address issues related to the PJM integration process. As a result of those
efforts, we transferred functional control of AEP's eastern transmission grid of
nearly 22,300 transmission miles to PJM Interconnection, a regional transmission
organization, on October 1, 2004. Our membership in PJM is expected to improve
the system reliability throughout the 12-state PJM RTO region.
Environmental
- -------------
We have announced plans to invest approximately $3.5 billion in capital from
2004 to 2010, and a total of $5 billion through 2020, to install pollution
control equipment that preserves the low cost generation from our coal-fired
power plants in the East. Fifty-one percent of our $3.5 billion capital plan
relates to Ohio generation facilities, followed by Virginia and West Virginia
with 35 percent, Kentucky with 9 percent and Indiana with 5 percent. Our
overall relationships with regulators are important to our growth strategy and
our goal of producing low-cost electricity with minimal impact on the
environment. It is important that we manage the regulatory process to ensure
that we receive fair recovery of our costs, including capital costs, as we
fulfill our commitment to invest in environmental projects at our generating
plants.
Overall Regulatory Matters and Regional Reorganization
- ------------------------------------------------------
Refocusing on the regulatory compact is essential to our success and will be
one of the main drivers of our performance in the future. The regulatory compact
is the means through which we make necessary investments to serve our customers
and in return are provided, through regulation, the opportunity to recover our
costs including a reasonable return on our investments. Our recent regional
reorganization along state and jurisdictional lines reinforces our focus on
customer service and aligns management with successful financial outcomes.
Texas Regulatory Activity
- -------------------------
Stranded Cost Recovery
- ----------------------
We continue to devote a great deal of time and effort to the issue of stranded
cost recovery in Texas. We cannot file our case for stranded cost recovery until
TCC's generation assets have been sold unless a waiver is granted. TCC
is evaluating and may seek a good-cause exception to the true-up rule to allow
us to file our True-up Proceedings before the sale of all of our TCC generation
assets is completed. The only asset sales pending are our Oklaunion and STP
interests. Both should be completed in the first half of 2005. The principal
component of the process is the net stranded generation costs (approximately
$1.3 billion). Other net regulatory assets may also be recovered through
customer transition charges.
The ultimate recovery of these assets is subject to what is expected to be a
contentious stranded cost True-up Proceeding. Although we believe that these
assets are recoverable under the Texas restructuring legislation, we anticipate
that other parties will contend that material amounts of stranded costs should
not be recovered. If these contentions are successful, in whole or in
substantial part, that would adversely affect future results of operations, cash
flows and financial condition.
TCC Rate Case
- -------------
TCC has a base rate filing before the Public Utility Commission of Texas (PUCT)
in which we are requesting an adjusted $41 million rate increase. After hearing
the case, the ALJ has recommended a reduction in existing rates of somewhere
between $33 million and $43 million depending on the final treatment of
consolidated tax savings. We have defended vigorously our request in briefs
submitted to the PUCT. Hearings were held on the consolidated tax savings
remand issue in September 2004. The PUCT is expected to issue a decision in
the fourth quarter of 2004.
Ohio Regulatory Activity
- ------------------------
Our strategy to invest capital in environmental assets has particular
significance in Ohio, our largest jurisdiction with 11,130 MW of generation and
1.5 million customers. Fifty one percent of our $3.5 billion environmental
capital plan is anticipated to be spent in Ohio. We have filed our proposed rate
stabilization plan which includes a 7% increase each year for the generation
component of the rate for Ohio Power Company customers and a 3% rate increase
each year for Columbus Southern Power Company customers beginning in 2006 and
ending in 2008. Our plan also offers the option to remove the current
residential 5% generation discount earlier than the statutory elimination at the
end of 2005 to reduce the annual percentage increase to residential customers.
The plan includes the opportunity annually to request an additional increase
averaging 4% per year for both companies if costs exceed the currently
anticipated level. Our Ohio Companies' Rate Stabilization Plans also provide for
the deferral of environmental construction and in-service carrying costs plus
PJM RTO administrative fees in 2004 and 2005 for recovery through a wires charge
in 2006 through 2008. The plan is designed to recover the cost increases that
are expected to result from environmental improvements to our Ohio generating
units and the costs of transmission reliability improvements from joining PJM. A
non-affiliated utility received an order which rejected its request for
automatic increases and deferrals during the Market Development Period (MDP).
The PUCO has indicated in FirstEnergy companies' rate stabilization plans that
these plans are specific to a company's requirements and characteristics and the
PUCO's order in one case should not be considered precedent for another
company's rate stabilization plan. Management is unable to predict how the PUCO
will rule regarding our rate stabilization filings. The PUCO is expected to
issue an order before the end of the 2004.
Energy Costs
- ------------
Coal, natural gas and oil prices have increased dramatically during 2004. These
increasing costs are the result of increasing worldwide demand, supply
uncertainty, and transportation constraints, as well as other factors that are
not fundamentally observable. We manage price risk, particularly around coal,
through long-term purchase contracts, fuel clauses in several jurisdictions and
other fuel procurement activities.
Improving Our Balance Sheet
- ---------------------------
We are utilizing and will continue to utilize the cash generated by the sale of
certain assets to reduce existing long-term debt and other obligations. During
the nine months ended September 30, 2004, we reduced total long-term debt by
approximately $1.5 billion, or 10%. The result of our use of cash on hand and
sales proceeds to reduce debt has decreased our debt to total capitalization
ratio from 64.6% at December 31, 2003 to 60.8% at September 30, 2004.
New Technology Plant
- --------------------
We intend to build a synthetic-gas-fired plant up to 1,000 MW of capacity in the
next five to six years utilizing integrated gasification combined cycle (IGCC)
technology. We estimate that this new plant will cost up to $1.6 billion. We
have not determined a location for the plant, but it will likely be in one of
our eastern states, because of ready access to coal. We will work with state
regulators and legislators to establish a framework for recovery of this
significant investment in new clean coal technology before site selection. Our
significant planned investments in emission control installations at existing
coal-fired plants and our commitment to IGCC technology reinforces our belief
that coal will be a lower emission energy source of the future and further
signals our commitment to investing in clean, environmentally safe technology.
Additional Information
- ----------------------
For additional information on our strategic outlook, see "Management's Financial
Discussion and Analysis of Results of Operations," including "Business
Strategy," in our 2003 Annual Report. Also see the remainder of our
"Management's Financial Discussion and Analysis of Results of Operations" in
this Form 10-Q, along with the Notes to Consolidated Financial Statements.
RESULTS OF OPERATIONS
- ---------------------
Segments
- --------
Our principal operating business segments and their major activities are:
o Utility Operations:
o Domestic generation of electricity for sale to retail and wholesale
customers.
o Domestic electricity transmission and distribution.
o Investments-Gas Operations:*
o Gas pipeline and storage services.
o Investments-UK Operations:**
o International generation of electricity for sale to wholesale customers.
o Coal procurement and transportation to our U.K. plants.
o Investments-Other:***
o Bulk commodity barging operations, windfarms, independent power
producers and other energy supply related businesses.
* Operations of Louisiana Intrastate Gas, including Jefferson Island
Storage, were classified as discontinued during 2003 and were sold
during the second and fourth quarter 2004, respectively.
** UK Operations were classified as discontinued during 2003 and were sold
during third quarter 2004.
*** Four independent power producers were sold during the third and fourth
quarter 2004.
There are numerous changes occurring in the businesses included in our segments
as a result of our continued divestiture of certain non-core operations.
Substantially all operations and assets within our Investments - UK Operations
segment were sold in July 2004. Within our Investments - Gas Operations segment,
we have recently sold LIG Pipeline Company, which included our gas pipeline
portion of Louisiana Intrastate Gas, and Jefferson Island Storage & Hub, L.L.C.,
which included our Louisiana gas storage assets held for sale. The only
substantive portion of the Investments - Gas Operations business that remains is
our Houston Pipe Line Company L.P. (HPL) operations, which includes the Bammel
storage facility and related pipeline assets. We will continue to operate HPL as
we evaluate our future plans for this investment.
In addition, there have been numerous divestitures of businesses, assets and
investments within our Investments - Other segment over the course of the past
nine months including AEP Coal and our interest in the Pushan Power Plant. We
also completed the sale of three independent power producers during the third
quarter 2004 and closed on the sale of a fourth independent power producer
facility early in the fourth quarter 2004. Our investment in South Coast Power
Limited, owner of the Shoreham Power Station in the U.K., was also sold in the
third quarter 2004. Our goal for the remaining assets in this segment, which
includes our unregulated investments in wind farms, and barging and river
transportation groups, is to operate them in such a way that they complement our
core capabilities in regulated utility operations.
All of the changes in these segments are leading us to review our business model
of the future and how we intend to manage our business overall. The decisions we
make over the course of the remainder of the year may lead to changes in our
reported business segments.
AEP Consolidated Results
- ------------------------
Our consolidated Net Income for the three and nine month periods ended September
30, 2004 and 2003 was as follows (Earnings and Average Shares Outstanding in
millions):
Third Quarter Nine Months Ended September 30,
------------------------------------------- --------------------------------------
2004 2003 2004 2003
------------------ -------------------- ---------------- -----------------
Earnings EPS Earnings EPS Earnings EPS Earnings EPS
-------- --- -------- --- -------- --- -------- ---
Utility Operations $359 $0.90 $409 $1.03 $845 $2.13 $940 $2.46
Investments - Gas Operations (28) (0.07) (21) (0.05) (41) (0.10) (64) (0.17)
Investments - Other 90 0.23 (45) (0.11) 91 0.23 (45) (0.12)
All Other* (9) (0.02) (36) (0.09) (43) (0.11) (54) (0.14)
----- ------ ----- ------ ----- ------ ----- ------
Income Before Discontinued Operations
and Cumulative Effect of Accounting
Changes 412 1.04 307 0.78 852 2.15 777 2.03
Investments - Gas Operations (3) - 2 - (2) - 6 0.01
Investments - UK Operations 120 0.30 (52) (0.13) 56 0.14 (89) (0.23)
Investments - Other 1 - - - 6 0.01 (15) (0.04)
----- ------ ----- ------ ----- ------ ----- ------
Discontinued Operations 118 0.30 (50) (0.13) 60 0.15 (98) (0.26)
Utility Operations - - - - - - 236 0.62
Investments - Gas Operations - - - - - - (22) (0.06)
Investments - UK Operations - - - - - - (21) (0.05)
----- ------ ----- ------ ----- ------ ----- ------
Cumulative Effect of Accounting Changes - - - - - - 193 0.51
----- ------ ----- ------ ----- ------ ----- ------
Total Net Income $530 $1.34 $257 $0.65 $912 $2.30 $872 $2.28
===== ====== ===== ====== ===== ====== ===== ======
Average Shares Outstanding 396 395 396 382
==== ==== ==== ====
* All Other includes the parent company interest income and expense, as well as other non-allocated costs.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Income Before Discontinued Operations and Cumulative Effect of Accounting
Changes increased $105 million to $412 million in third quarter 2004 compared to
third quarter 2003. Net Income for third quarter 2004 of $530 million or $1.34
per share includes a gain, net of taxes, from discontinued operations of $118
million. Net Income for third quarter 2003 of $257 million or $0.65 per share
includes a loss, net of taxes, from discontinued operations of $50 million.
For the third quarter 2004 our Utility Operations Earnings decreased $50
million, or 12%, from the previous year driven primarily by the absence of the
Texas wholesale capacity auction true-up revenue in 2004 and milder weather in
the summer months of 2004 offset by higher industrial load growth.
Earnings from our UK Operations (which were sold on July 30, 2004) improved $172
million in the third quarter 2004 as compared to the same period in 2003
primarily due to a gain of $127 million, net of tax, on the sale. These
operations had impairment losses in 2003. Please refer to our 2003 Annual
Report for further discussion.
Earnings from our Gas Operations decreased $12 million from the previous year
reflecting a decrease in results from storage-related gas valuation losses,
which we expect will reverse in future periods.
Earnings from our Investments - Other segment increased $136 million. This
segment benefited from the sale of three of our IPP investments and the sale of
our 50 percent interest in South Coast Power Limited, owner of the Shoreham
Power Station in the U.K. in 2004 compared to the same period in 2003, which
included impairments on the IPPs. We recorded $95 million in gains from the sale
of these investments during the third quarter 2004.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Income Before Discontinued Operations and Cumulative Effect of Accounting
Changes increased $75 million to $852 million in 2004 compared to 2003. Net
Income for 2004 of $912 million or $2.30 per share includes a gain, net of
taxes, from discontinued operations of $60 million. Net Income for 2003 of $872
million or $2.28 per share includes a loss, net of taxes, from discontinued
operations of $98 million and a benefit from a net $193 million of cumulative
effect of changes in accounting related to asset retirement obligations and
accounting for risk management contracts.
For the nine months ended September 30, 2004, Utility Operations Income Before
Discontinued Operations and Cumulative Effect of Accounting Changes decreased
$95 million or 10% from the previous year primarily due to the absence of the
Texas wholesale capacity auction true-up revenue in 2004.
Reduced losses at our UK Operations, included in discontinued operations, were
responsible for $166 million (including cumulative effect of accounting changes)
of the increase in Net Income in 2004. In July 2004, we completed the sale of
substantially all operations and assets within our Investments - UK Operations
segment resulting in a gain of $127 million, net of tax, on the sale. These
operations had impairment losses in 2003. Please refer to our 2003 Annual
Report for further discussion.
Our Investments - Gas Operations segment posted a lower loss in 2004 due to
improved pipeline operations and lower operating expenses.
Our results of operations by operating segment are discussed below.
Utility Operations
- ------------------
Third Quarter Nine Months Ended September 30,
---------------------- -------------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Revenues $2,946 $3,112 $8,095 $8,483
Fuel and Purchased Power 1,054 1,121 2,635 2,967
------- ------- ------- -------
Gross Margin 1,892 1,991 5,460 5,516
Depreciation and Amortization 322 317 940 927
Other Operating Expenses 895 899 2,806 2,659
------- ------- ------- -------
Operating Income 675 775 1,714 1,930
Other Income (Expense), Net 7 15 32 18
Interest Charges and Preferred
Stock Dividend Requirements 151 168 471 499
Income Tax Expense 172 213 430 509
------- ------- ------- -------
Income Before Discontinued
Operations and Cumulative Effect of
Accounting Changes $359 $409 $845 $940
======= ======= ======= =======
Summary of Selected Sales Data
For Utility Operations
Third Quarter Nine Months Ended September 30,
------------------------ -------------------------------
2004 2003 2004 2003
---- ---- ---- ----
Energy Summary (in millions of KWH)
Retail:
Residential 12,002 12,578 35,169 34,658
Commercial 10,070 10,267 28,240 27,834
Industrial 13,052 12,309 38,227 36,764
Miscellaneous 857 827 2,406 2,251
------- ------- -------- --------
Subtotal 35,981 35,981 104,042 101,507
Texas Retail and Other 316 725 802 2,264
------- ------- -------- --------
Total 36,297 36,706 104,844 103,771
======= ======= ======== ========
Wholesale: 23,613 19,669 62,838 56,385
======= ======= ======== ========
Summary of Selected Data
For Utility Operations
Third Quarter Nine Months Ended September 30,
------------------------ -------------------------------
2004 2003 2004 2003
---- ---- ---- ----
Weather Summary (in degree days)
Eastern Region
- --------------
Actual - Heating 1 12 2,032 2,181
Normal - Heating* 7 1,993 1,979
Actual - Cooling 553 592 869 750
Normal - Cooling* 679 960 962
Western Region (PSO/SWEPCo)
- ---------------------------
Actual - Heating 0 0 913 1,074
Normal - Heating* 2 1,013 1,006
Actual - Cooling 1,178 1,390 1,867 2,034
Normal - Cooling* 1,398 2,058 2,050
*Normal Heating/Cooling represents the 30-year average of degree days.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Reconciliation of Third Quarter 2003 to Third Quarter 2004
Income Before Discontinued Operations and Cumulative Effect of Accounting Changes
(in millions)
Third Quarter 2003 $409
Changes in Gross Margin:
------------------------
Retail Margins (2)
Texas Supply (10)
Wholesale Capacity Auction Revenues (61)
Off-System Sales (26)
----
(99)
Changes in Operating And Other Expenses:
----------------------------------------
Operations and Maintenance (3)
Depreciation and Amortization (5)
Taxes, Other 7
Other Income (Expense), Net (8)
Interest Charges 17
----
8
Income Tax Expense 41
-----
Third Quarter 2004 $359
=====
Income from Utility Operations decreased $50 million to $359 million in 2004.
The key driver of the decrease was a $99 million decrease in gross margin
partially offset by an $8 million net decrease in operating and other expenses,
and a $41 million decrease in income taxes.
The major components of our change in gross margin, defined as utility revenues
net of related fuel and purchased power, were as follows:
o Overall retail margins in our utility business were slightly below last
year. Residential demand decreased from the prior year as a result of
lower usage by customers due to mild weather in the summer months of
2004 across most of the service territory. Cooling degree days were
down in both the East and the West as compared to the prior year.
Partially offsetting the mild weather were favorable results from
residential and commercial customer growth and increased demand in
industrial classes from the continuing economic recovery in our
regions.
o Our Texas supply business had a $10 million decrease in gross margin as
a result of increased purchased power costs due to the divestiture of
assets, and pursuant to our energy supply commitments we made to our
wholesale customers, at the end of the second quarter of 2004.
o Beginning in 2004, the wholesale capacity auction true-up ceased per
rules of the PUCT. Related revenues are no longer recognized, resulting
in $61 million of lower regulatory deferrals in 2004. For the years
2003 and 2002, we recognized revenues for the wholesale capacity
auction true-up for TCC as a regulatory asset for the difference
between the actual market prices based upon the state-mandated auction
of 15% of generation capacity and the earlier estimate of market price
used in the PUCT's excess cost over market model.
o Margins from off-system sales for 2004 were $26 million lower than 2003
primarily due to lower optimization activity.
Utility Operating and Other Expenses changed between years as follows:
o Interest expense decreased $17 million due to the refinancing of higher
coupon debt and the retirement of debt.
o Income Tax expense decreased $41 million largely due to the decrease in
pre-tax income and other tax return adjustments.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Reconciliation of Nine Months Ended September 30, 2003 to Nine Months Ended September 30, 2004
Income Before Discontinued Operations & Cumulative Effect of Accounting Changes
(in millions)
Nine Months Ended September 30, 2003 $940
Changes in Gross Margin:
------------------------
Retail Margins 119
Texas Supply (52)
Wholesale Capacity Auction Revenues (169)
Off-System Sales 34
Other 12
-----
(56)
Changes in Operating And Other Expenses:
----------------------------------------
Operations and Maintenance (138)
Depreciation and Amortization (13)
Taxes, Other (9)
Other Income (Expense), Net 14
Interest Charges 28
-----
(118)
Income Tax Expense 79
-----
Nine Months Ended September 30, 2004 $845
=====
Income from Utility Operations, before a $236 million cumulative effect of
accounting changes in 2003, decreased $95 million in 2004 to $845 million. Key
drivers of the change include $118 million increase in operating and other
expenses, a $56 million decrease in gross margin and a $79 million decrease in
income taxes.
The major components of our change in gross margin, defined as utility revenues
net of related fuel and purchased power, were as follows:
o Overall retail margins (excluding fuel recovery) in our utility
business increased $60 million. Demand in the East and the West
increased over the prior year as a consequence of higher usage in most
classes and customer growth in the residential and commercial classes.
Commercial and industrial demand also increased resulting from the
economic recovery in our regions. Milder weather during the summer
months of 2004 partially offset these favorable results.
o Fuel recovery in our non-Texas utility operations was a net $59 million
favorable in comparison to last year due to higher fuel costs in the
prior year resulting primarily from the conclusion of the amortization
of deferred Cook plant outage costs and a fish intrusion outage causing
us to purchase higher priced non-nuclear replacement power in 2003.
o Our Texas supply business had a $52 million decrease in gross margin
principally due to the divestiture of TCC generation assets to comply
with Texas stranded cost recovery regulations. This resulted in higher
purchased power costs to fulfill contractual commitments.
o Beginning in 2004, the wholesale capacity auction true-up ceased per
rules of the PUCT. Related revenues are no longer recognized, resulting
in $169 million of lower regulatory deferrals in 2004. For the years
2003 and 2002, we recognized the revenues for the wholesale capacity
auction true-up for TCC as a regulatory asset for the difference
between the actual market prices based upon the state-mandated auction
of 15% of generation capacity and the earlier estimate of market price
used in the PUCT's excess cost over market model.
o Margins from off-system sales for 2004 were $34 million better than
in 2003 due to favorable optimization activity, somewhat offset by lower
volumes.
Utility Operating and Other Expenses changed between years as follows:
o Maintenance and Other Operation expense increased $138 million due to a
$67 million increase in generation expenses primarily due to the timing
of planned plant outages in 2004 as compared to 2003, and increases in
related chemical expenses. Additionally, distribution maintenance expense
increased $39 million from system reliability work. Other increases of $22
million include employee benefits, insurance, and other administrative and
general expenses, magnified by favorable adjustments in 2003. These
increases were offset, in part, by $30 million due to the conclusion of
the amortization of our deferred Cook nuclear plant restart settlement
expenses. Expenses of $40 million, comprised of various miscellaneous
items, make up the remainder of the increase.
o Depreciation and amortization expense increased $13 million primarily
due to a higher depreciable asset base, including the addition of
capitalized software costs, increased amortization of regulatory
assets, and the consolidation of JMG at Ohio Power (which had no impact
on net income). These increases more than offset the decrease in
expense at AEP Texas Central, which is due primarily to the cessation
of depreciation on plants classified as held for sale.
o Taxes other than income taxes increased $9 million due to increased property
tax values and assessments.
o Interest expense decreased $28 million from the prior period due to the
refinancings of higher coupon debt.
o Income Tax expense decreased $79 million due to the decrease in pre-tax
income and other prior year tax return adjustments.
Investments - Gas Operations
- ----------------------------
Third Quarter Nine Months Ended September 30,
------------------- -------------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Revenues $746 $773 $2,214 $2,396
Purchased Gas 739 747 2,124 2,321
----- ----- ------- -------
Gross Margin 7 26 90 75
Maintenance and Other Operation 34 40 94 114
Other Operating Expenses 3 - 9 11
----- ----- ------- -------
Operating Loss (30) (14) (13) (50)
Other Income (Expense), Net - (3) (9) (8)
Interest Expense 14 15 39 41
Income Tax Benefit 16 11 20 35
----- ----- ------- -------
Net Loss Before Discontinued Operations and Cumulative
Effect of Accounting Changes $(28) $(21) $(41) $(64)
===== ===== ======= =======
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Our $28 million loss from Gas Operations before discontinued operations and
cumulative effect of accounting changes compares with a $21 million loss
recorded in the third quarter of 2003. Gross margins decreased $19 million
year-over-year primarily due to valuation changes on price risk management of
fully-hedged physical gas inventories. As gas was injected into storage during
the spring and summer, we hedged the price risk by selling corresponding
quantities in the winter months. As compared to the prior year, we recognized
storage related valuation losses of approximately $23 million on these
fully-hedged positions, which will reverse as margins are recognized when gas is
withdrawn and delivered in future periods. Operating expenses increased by $3
million. Income tax benefits increased by $5 million due to the decrease in
pre-tax income.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Our $41 million loss from Gas Operations before discontinued operations and
cumulative effect of accounting changes compares with a $64 million loss
recorded in the year-to-date September 2003 period. Gross margins improved $15
million year-to-date September 30, 2004 to $90 million. As compared to the prior
year, current year margins have been reduced by $25 million due primarily to
valuation changes on fully-hedged inventory positions, which will reverse as
margins are recognized when gas is withdrawn and delivered in future periods.
Without this impact, margins would have been approximately $40 million higher in
the first nine months 2004 than the first nine months of 2003. This was driven
by $20 million of significant losses in 2003 from servicing a single contract,
improved earnings from the pipeline operations, and the avoidance of prior year
margin losses from the eliminated trading activities. In addition, operating
expenses decreased $22 million between periods as a result of gas trading
activities which have been eliminated and lower depreciation resulting from 2003
asset impairments. Income tax benefits decreased by $15 million primarily due to
the improvement in pre-tax income.
Investments - UK Operations
- ---------------------------
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Net income from our Investments - UK Operations segment (all classified as
Discontinued Operations) increased to $120 million in income, which includes a
gain on sale of $127 million in 2004, compared with a loss of $52 million in
2003. During late 2003, we concluded that the UK Operations were not part of
our core business and we began actively marketing our investment. In July 2004,
we completed the sale of substantially all operations and assets within our
Investments - UK Operations segment. Included in the sale are the generating
assets, commodity contracts, including electricity sales contracts, coal
purchase and sale contracts and freight contracts with a number of different
market counterparties for varying contract periods. The remaining assets and
liabilities include certain coal, power and capacity positions and financial
coal and freight swaps. The majority of these positions will either mature or
be settled with the applicable counterparties during the fourth quarter 2004.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Income from our Investments - UK Operations segment (all classified as
Discontinued Operations) increased to $56 million in income, which includes a
gain on sale of $127 million in 2004, compared with a loss of $89 million in
2003, before the cumulative effect of accounting change. During late 2003, we
concluded that the UK Operations were not part of our core business and we began
actively marketing our investment. In July 2004, we completed the sale of
substantially all operations and assets within our Investments - UK Operations
segment.
Investments - Other
- -------------------
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Income before discontinued operations and cumulative effect of accounting
changes from our Investments - Other segment increased by $135 million in 2004,
primarily due to an after-tax gain of approximately $64 million resulting from
the sale in July 2004 of our ownership interests in our two independent power
producers (IPPs) in Florida (Mulberry and Orange), and one in Colorado (Brush
II), and an after-tax gain of approximately $31 million resulting from the sale
of our 50 percent interest in South Coast Power Limited, owner of the Shoreham
Power Station in the UK. In addition, results in the current quarter did not
include a $45 million after-tax impairment in the third quarter of 2003, related
to our investment in the IPPs.
The above increases were primarily offset by a $2 million decrease in results at
our MEMCO operations due primarily to operational items and a $3 million
decrease at our IPPs and windfarms, resulting primarily from the sale of three
of our IPPs in the third quarter 2004.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Income before discontinued operations and cumulative effect of accounting
changes from our Investments - Other segment increased from a loss of $45
million to $91 million of income in 2004.
The key components of the increase in income were as follows:
o We recorded an after-tax gain of approximately $64 million resulting from
the sale in July 2004 of our ownership interests in our two independent
power producers in Florida (Mulberry and Orange),
o We recorded an after-tax gain of approximately $31 million resulting from
the sale of our 50% interest in South Coast Power Limited, owner of the
Shoreham Power Station in the U.K.,
o Our results in 2004 did not include a $45 million after-tax impairment
in the third quarter of 2003, related to our investment in the Colorado
IPPs.
o Our results at our MEMCO operations increased $2 million in 2004 due to a
stronger freight market in the nine month period in 2004 as compared to
2003.
o Our AEP Texas Provider of Last Resort (POLR) entity recorded a $6 million
provision for uncollectible receivables in the first six months of 2003
that did not recur in 2004,
o Our AEP Resources entity decreased its loss by $17 million in 2004 versus
2003, primarily due to lower interest expense resulting from equity capital
infusions in mid and late 2003 that were used to reduce debt and other
corporate borrowings, and
o Our AEP Pro Serv entity reduced losses from $4 million to break even,
primarily due to operations winding down in 2004.
Offsetting these increases was the absence during 2004 of a $31 million
nonrecurring gain recorded in the first quarter of 2003 primarily related to a
gain from the sale of Mutual Energy and a $2 million decrease in results at
our IPPs and windfarms resulting primarily from the sale of three of our IPPs
in the third quarter 2004.
In discontinued operations, the Eastex Cogeneration facility near Longview,
Texas was sold in the third quarter 2003 and Pushan Power Plant was sold in
March 2004.
All Other
- ---------
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Our parent company's third quarter 2004 expenses decreased $27 million from the
level in the third quarter of 2003 due to a $23 million net decrease in expenses
primarily resulting from lower general advertisement expenses in 2004 and a
non-recurring, unfavorable receivable write-off in the prior period. Interest
expense was $6 million lower in the current period due to lower fixed rate
financing and buy back of parent bonds, and parent guarantee fee income from
subsidiaries was lower by $2 million compared to the prior period.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Our parent company's year-to-date 2004 expenses decreased $11 million from the
level in the year-to-date period of 2003 due to a $28 million net decrease in
expenses primarily resulting from lower insurance premiums and lower general
advertisement expenses in 2004 and a non-recurring, unfavorable receivable
write-off in the prior period. Interest income was $12 million lower in the
current period due to lower money pool and cash balances along with higher
interest rates on invested funds in 2003. Additionally, parent guarantee fee
income from subsidiaries was lower by $5 million compared to the prior period
due to the reduction of trading activities.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 33.0% and
35.8% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
temporary differences, permanent differences, energy production credits,
amortization of investment tax credits and state income taxes. The decrease in
the effective tax rate is primarily due to federal income tax return
adjustments.
The effective tax rates for the first nine months of 2004 and 2003 were 34.1%
and 35.4% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
temporary differences, permanent differences, energy production credits,
amortization of investment tax credits and state income taxes. The effective tax
rates remained relatively flat for the comparative period.
FINANCIAL CONDITION
- -------------------
We measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Capitalization
- --------------
September 30, December 31,
2004 2003
---- ----
Common Equity 38.9% 35.1%
Preferred Stock 0.3 0.3
Preferred Stock (Subject to Mandatory Redemption) 0.3 0.3
Long-term Debt, including amounts due within one year 59.5 62.8
Short-term Debt 1.0 1.5
------ ------
Total Capitalization 100.0% 100.0%
====== ======
Our $2.3 billion in cash flows from operations, combined with our reduction in
cash expenditures for investments in discontinued operations, the proceeds from
asset sales, a reduction in the dividend beginning in the second quarter of 2003
and the use of a portion of our cash on hand, allowed us to reduce long-term
debt by $1.5 billion and short-term debt by $112 million.
Our common equity increased due to the issuance of $13 million of new common
equity (related to our incentive compensation plans) and the fact that our
earnings exceeded our dividends for the nine months ended September 30, 2004.
As a consequence of the capital changes during the nine months, we improved our
ratio of debt to total capital from 64.6% to 60.8% (preferred stock subject to
mandatory redemption is included in debt component of ratio).
Liquidity
- ---------
Liquidity, or access to cash, is an important factor in determining our
financial stability. We are committed to preserving an adequate liquidity
position.
Credit Facilities
- -----------------
We manage our liquidity by maintaining adequate external financing commitments.
We had an available liquidity position, at September 30, 2004, of approximately
$4 billion as illustrated in the table below.
Amount Maturity
------ --------
(in millions)
Commercial Paper Backup:
Lines of Credit $1,000 May 2005
Lines of Credit 750 May 2006
Lines of Credit 1,000 May 2007
Letter of Credit Facility 200 September 2006
-------
Total 2,950
Cash and Cash Equivalents 1,282
-------
Total Liquidity Sources 4,232
Less: AEP Commercial Paper
Outstanding 180(a)
Letters of Credit
Outstanding 36
-------
Net Available Liquidity at
September 30, 2004 $4,016
=======
(a) Amount does not include JMG Funding LP commercial paper outstanding
in the amount of $20 million. This commercial paper is specifically
associated with the Gavin scrubber lease and does not reduce
available liquidity to AEP. The JMG Funding LP commercial paper is
supported by a separate letter of credit facility
not included above.
Debt Covenants and Borrowing Limitations
- ----------------------------------------
Our revolving credit agreements contain certain covenants and require us to
maintain our percentage of debt to total capitalization at a level that does not
exceed 67.5%. The method for calculating our outstanding debt and other capital
is contractually defined. At September 30, 2004, we were in compliance with the
covenants contained in these credit agreements and contractual debt to total
capitalization was 56.2%. Non-performance of these covenants could result in an
event of default under these credit agreements. In addition, the acceleration of
our payment obligations, or certain obligations of our subsidiaries, prior to
maturity under any other agreement or instrument relating to debt outstanding in
excess of $50 million would cause an event of default under these credit
agreements and permit the lenders to declare the amounts outstanding to be
payable.
Our revolving credit facilities generally prohibit new borrowings if we
experience a material adverse change in our business or operations. We may,
however, make new borrowings under these facilities if we experience a material
adverse change so long as the proceeds of such borrowings are used to repay
outstanding commercial paper.
Under an SEC order, we and our utility subsidiaries cannot incur additional
indebtedness if the issuer's common equity would constitute less than 30% (25%
for TCC) of its capital. In addition, this order restricts us and our utility
subsidiaries from issuing long-term debt unless that debt will be rated
investment grade by at least one nationally recognized statistical rating
organization. At September 30, 2004, we were in compliance with this order.
Money pool and external borrowings may not exceed SEC or state commission
authorized limits. At September 30, 2004, we had not exceeded the SEC or state
commission authorized limits.
Credit Ratings
- --------------
We continue to take steps to improve our credit quality, including executing
plans during 2004 to further reduce our outstanding debt through the use of
proceeds from our planned dispositions and other available cash on hand.
AEP's ratings have not been adjusted by any rating agency during 2004. On August
2, 2004, Moody's Investors Service (Moody's) changed their outlook on AEP to
"positive" from "stable," while keeping the remaining rated subsidiaries
on "stable" outlook. The other major rating agencies currently have AEP and our
rated subsidiaries on "stable" outlook.
Our current ratings by the major agencies are as follows:
Moody's S&P Fitch
------- --- -----
AEP Short-term Debt P-3 A-2 F-2
AEP Senior Unsecured Debt Baa3 BBB BBB
If AEP or any of its rated subsidiaries receive an upgrade from any of the
rating agencies listed above, our borrowing costs could decrease. If we receive
a downgrade in our credit ratings by one of the nationally recognized rating
agencies listed above, our borrowing costs could increase and access to borrowed
funds could be negatively affected.
Common Stock Dividends
- ----------------------
After the completion of our planned divestitures and after the results of our
Ohio and Texas rate proceedings are known, we hope to be able to recommend to
the Board of Directors a modest increase in our common stock dividend from its
current quarterly level of 35 cents per share.
Cash Flow
- ---------
Our cash flows are a major factor in managing and maintaining our liquidity
strength.
Nine Months Ended September 30,
2004 2003
---- ----
(in millions)
Cash and Cash Equivalents at Beginning of Period $976 $1,084
------- -------
Net Cash Flows From Operating Activities 2,265 1,756
Net Cash Flows From (Used For) Investing Activities 130 (1,540)
Net Cash Flows From (Used For) Financing Activities (2,089) 320
------- -------
Net Increase in Cash and Cash Equivalents 306 536
------- -------
Cash and Cash Equivalents at End of Period $1,282 $1,620
======= =======
Cash from operations, combined with a bank-sponsored receivables purchase
agreement and short-term borrowings, provide necessary working capital and help
us meet other short-term cash needs.
We use our corporate borrowing program to meet the short-term borrowing needs of
our subsidiaries. The corporate borrowing program includes a utility money pool,
which funds the utility subsidiaries, and a non-utility money pool, which funds
the majority of the non-utility subsidiaries. In addition, we also fund, as
direct borrowers, the short-term debt requirements of our other subsidiaries
that are not participants in the non-utility money pool. As of September 30,
2004, we had credit facilities totaling $2.75 billion to support our commercial
paper program. At September 30, 2004, we had $214 million outstanding in
short-term borrowings of which $180 million was commercial paper supported by
the revolving credit facilities. In addition, JMG had commercial paper
outstanding in the amount of $20 million. This commercial paper is specifically
associated with the Gavin scrubber lease and is not supported by our credit
facilities. The maximum amount of commercial paper outstanding during the
quarter ended September 30, 2004 was $529 million. The weighted-average interest
rate for our commercial paper during the third quarter 2004 was 2.05%.
We generally use short-term borrowings to fund working capital needs, property
acquisitions and construction until long-term funding alternatives are arranged.
Sources of long-term funding include issuance of common stock, preferred stock
or long-term debt and sale-leaseback or leasing agreements.
Operating Activities
- -------------------- Nine Months Ended September 30,
2004 2003
---- ----
(in millions)
Net Income $912 $872
Discontinued Operations (60) 98
------- -------
Income from Continuing Operations 852 970
Noncash Items Included in Earnings 1,223 1,033
Changes in Assets and Liabilities 190 (247)
------- -------
Net Cash Flows From Operating Activities $2,265 $1,756
======= =======
2004 Operating Cash Flow
- ------------------------
Our cash flows from operating activities were $2.3 billion for the first nine
months of 2004. We produced income from continuing operations of $852 million
during the period. Income from continuing operations for the period included
noncash expense items of $1.1 billion for depreciation, amortization and
deferred taxes. In addition, there is a current period favorable impact for a
net $89 million balance sheet change for risk management contracts that are
marked-to-market. These contracts have an unrealized earnings impact as market
prices move, and a cash impact upon settlement or upon disbursement or receipt
of premiums. The other changes in assets and liabilities represent items that
had a current period cash flow impact, such as changes in working capital, as
well as items that represent future rights or obligations to receive or pay
cash, such as regulatory assets and liabilities. The current period activity in
these asset and liability accounts relates to a number of items; the most
significant are an increase in the balance of fuel, materials and supplies of
$83 million and an increase in the balance of accrued taxes of $388 million.
2003 Operating Cash Flow
- ------------------------
Our cash flows from operating activities were $1.8 billion for the first nine
months of 2003. We produced income from continuing operations of $970 million
during the period. Income from continuing operations for the period included
noncash items of $1.2 billion for depreciation, amortization, and deferred
taxes, offset by $193 million related to the cumulative effect of accounting
changes. There was a current period unfavorable impact for a net $124 million
balance sheet change for risk management contracts that were marked-to-market.
These contracts have an unrealized earnings impact as market prices move, and a
cash impact upon settlement or upon disbursement or receipt of premiums. Other
activity in the asset and liability accounts related to the wholesale capacity
auction true-up asset (ECOM) of $169 million, an increase in customer deposits
and risk management collateral of $102 million and changes in accounts
receivable and accounts payable of $267 million.
Investing Activities
- --------------------
Nine Months Ended September 30,
2004 2003
---- ----
(in millions)
Construction Expenditures $(1,034) $(936)
Change in Other Cash Deposits, Net 27 36
Investment in Discontinued Operations, net (59) (686)
Proceeds from Sales of Assets 1,202 49
Other (6) (3)
-------- --------
Net Cash Flows From (Used for) Investing Activities $130 $(1,540)
======== ========
Our cash flows used for investing activities decreased $1.7 billion from the
same period in the prior year primarily due to proceeds from the sales of assets
in 2004 and investments made in our U.K. operations during 2003 that did not
recur during 2004.
Financing Activities
- --------------------
Nine Months Ended September 30,
2004 2003
---- ----
(in millions)
Issuances of Common Stock $13 $1,142
Issuances/Retirements of Debt, net (1,683) (116)
Retirement of Preferred Stock (4) (2)
Retirement of Minority Interest - (225)
Dividends (415) (479)
-------- -------
Net Cash Flows From (Used for) Financing Activities $(2,089) $320
======== =======
Our cash flow from financing activities in 2004 decreased $2.4 billion from the
$320 million net cash inflow recorded in 2003. During the first quarter of 2003,
we issued common stock for $1.1 billion and subsequent to the first quarter of
2003, we reduced our dividend. This compares to only $13 million of cash
proceeds from the issuance of common stock under our incentive compensation
plans in the first nine months of 2004.
During the first nine months of 2004, we used approximately $1.9 billion of cash
to retire long-term debt. We also issued approximately $425 million of long-term
debt ($416 million net of issuance costs) including $222 million of pollution
control bonds (installment purchase contracts). These activities were supported
by the generation of $2.3 billion in cash flow from operations. See Note 10
"Financing Activities" for further information regarding issuances and
retirements of debt instruments during the first nine months of 2004.
Off-balance Sheet Arrangements
- ------------------------------
We enter into off-balance sheet arrangements for various business reasons
including accelerating cash collections, reducing operational expenses and
spreading risk of loss to third parties. Our current policy restricts the use of
off-balance sheet financing entities or structures, except for traditional
operating lease arrangements and sales of customer accounts receivable that we
enter in the normal course of business. Our off-balance sheet arrangements have
not changed significantly from year-end. For complete information on each of
these off-balance sheet arrangements see the "Minority Interest and Off-balance
Sheet Arrangements" in "Management's Financial Discussion and Analysis of
Results of Operations" section of the 2003 Annual Report.
Other
- -----
Power Generation Facility
- -------------------------
We have agreements with Juniper Capital L.P. (Juniper) under which Juniper
constructed and financed a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and leased the Facility to us. We have
subleased the Facility to the Dow Chemical Company (Dow). The Facility is a
Dow-operated "qualifying cogeneration facility" for purposes of PURPA.
Commercial operation of the Facility as required by the agreements between
Juniper, AEP and Dow was achieved on March 18, 2004. The initial term of our
lease with Juniper (Juniper Lease) commenced on March 18, 2004 and terminates on
June 17, 2009. We may extend the term of the Juniper Lease for up to 30 years.
Our lease of the Facility is reported as an owned asset under a lease financing
transaction. Therefore, the asset and related liability for the debt and equity
of the facility are recorded on AEP's balance sheet.
Juniper is an unaffiliated limited partnership, formed to construct or otherwise
acquire real and personal property for lease to third parties, to manage
financial assets and to undertake other activities related to asset financing.
At September 30, 2004, Juniper's acquisition costs for the Facility totaled $520
million, and we estimate total costs for the completed Facility to be
approximately $525 million, funded through long-term debt financing of $494
million and equity of $31 million from investors with no relationship to AEP or
any of AEP's subsidiaries. For the initial 5-year lease term, the base lease
rental is equal to the interest on Juniper's debt financing at a variable rate
indexed to three-month LIBOR (1.975% on September 30, 2004) plus 100 basis
points, plus a fixed return on Juniper's equity investment in the Facility and
certain other fixed amounts. Consequently, as LIBOR increases, the base rental
payments under the Juniper Lease will also increase.
The Facility is collateral for Juniper's debt financing. Due to the treatment of
the Facility as a financing of an owned asset, we recognized all of Juniper's
obligations as a liability of $520 million. Upon expiration of the lease, our
actual cash obligation could range from $0 to $415 million based on the fair
value of the assets at that time. However, if we default under the Juniper
Lease, our maximum cash payment could be as much as $525 million.
Dow uses a portion of the energy produced by the Facility and sells the excess
energy. OPCo has agreed to purchase up to approximately 800 MW of such excess
energy from Dow. Because the Facility is a major steam supply for Dow, Dow is
expected to operate the Facility at certain minimum levels, and OPCo is
obligated to purchase the energy generated at those minimum operating levels
(expected to be approximately 270 MW).
OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel
Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and
Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in
excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity,
energy and ancillary services to TEM pursuant to the PPA that TEM rejected as
non-conforming. Commercial operation for purposes of the PPA began April 2,
2004.
On September 5, 2003, TEM and AEP separately filed declaratory judgment actions
in the United States District Court for the Southern District of New York. We
allege that TEM has breached the PPA, and we are seeking a determination of our
rights under the PPA. TEM alleges that the PPA never became enforceable, or
alternatively, that the PPA has already been terminated as the result of AEP
breaches. If the PPA is deemed terminated or found to be unenforceable by the
court, we could be adversely affected to the extent we are unable to find other
purchasers of the power with similar contractual terms and to the extent we do
not fully recover claimed termination value damages from TEM. The corporate
parent of TEM (Tractebel SA) has provided a limited guaranty.
On November 18, 2003, the above litigation was suspended pending final
resolution in arbitration of all issues pertaining to the protocols relating to
the dispatching, operation, and maintenance of the Facility and the sale and
delivery of electric power products. In the arbitration proceedings, TEM argued
that in the absence of mutually agreed upon protocols there were no commercially
reasonable means to obtain or deliver the electric power products and therefore
the PPA is not enforceable. TEM further argued that the creation of the
protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on
February 11, 2004 and concluded that the "creation of protocols" was not subject
to arbitration, but did not rule upon the merits of TEM's claim that the PPA is
not enforceable. Management believes the PPA is enforceable. The litigation is
now in the discovery phase.
On March 26, 2004, OPCo requested that TEM provide assurances of performance of
its future obligations under the PPA, but TEM refused to do so. As indicated
above, OPCo also gave notice to TEM and declared April 2, 2004 as the
"Commercial Operations Date." Despite OPCo's prior tenders of replacement
electric power products to TEM beginning May 1, 2003 and despite OPCo's tender
of electric power products from the Facility to TEM beginning April 2, 2004, TEM
refused to accept and pay for them under the terms of the PPA. On April 5, 2004,
OPCo gave notice to TEM that OPCo, (i) was suspending performance of its
obligations under the PPA, (ii) would be seeking a declaration from the New York
federal court that the PPA has been terminated and (iii) would be pursuing
against TEM, and Tractebel SA under the guaranty, damages and the full
termination payment value of the PPA.
SIGNIFICANT MATTERS
- -------------------
Progress Made on Announced Divestitures
- ---------------------------------------
We are continuing with our announced plan to divest significant components of
our non-regulated assets, including certain domestic and international
unregulated generation, part of our gas pipeline and storage business, a coal
business and certain IPPs. In addition to the following discussion, see Note 7
of our Notes to Consolidated Financial Statements within this Form 10-Q.
Pushan Power Plant
- ------------------
In December 2003, we signed an agreement to sell our interest in the Pushan
Power Plant in Nanyang, China to our minority interest partner. The sale was
completed in March 2004 and the effect of the sale on our first quarter results
of operations was not significant.
Texas Generation
- ----------------
We made progress on our planned divestiture of certain Texas generation assets
by (1) announcing in June 2004 and September 2004 that we had signed agreements
to sell TCC's 7.81% share of the Oklaunion Power Station to two unaffiliated
co-owners of the plant for approximately $43 million, subject to closing
adjustments, (2) announcing in September 2004 that we had signed agreements to
sell TCC's 25.2% share of the STP nuclear plant to two unaffiliated co-owners of
the plant for approximately $333 million, subject to closing adjustments, and
(3) in July 2004 closing on the sale of TCC's remaining generation assets,
including eight natural gas plants, one coal-fired plant and one hydro-electric
plant for approximately $425 million, net of adjustments. We expect the sales of
Oklaunion and STP to be completed by in the first half of 2005. Nevertheless,
there could be potential delays in receiving necessary regulatory approvals and
clearances and there could be delays in resolving litigation with a third party
affecting Oklaunion which could delay the closings. We will file with the PUCT
to recover net stranded costs associated with the sales pursuant to Texas
restructuring legislation. Stranded costs will be calculated on the basis of all
generation assets, not individual plants.
AEP Coal
- --------
As a result of our decision to exit our non-core businesses, we retained an
advisor in 2003 to facilitate the sale of AEP Coal. In March 2004, we reached an
agreement to sell assets, exclusive of certain reserves and related liabilities,
of the mining operations of AEP Coal. The sale closed in April 2004 and the
effect of the sale on second quarter 2004 results of operations was not
significant.
Gas Operations
- --------------
In February 2004, we signed an agreement to sell LIG Pipeline Company, which
contained the pipeline and processing assets of Louisiana Intrastate Gas (LIG).
The sale was completed in early April 2004 and the impact on results of
operations in the second quarter of 2004 was not significant. In October 2004,
we completed the sale of Jefferson Island Storage & Hub, L.L.C., the remaining
LIG gas storage entity. The sale resulted in an additional $12.3 million pre-tax
loss ($2 million, net of tax) recorded in the third quarter 2004. We continue to
evaluate the merits of retaining or selling our interest in Houston Pipe Line
Company L.P., including the Bammel storage facility, which is part of our
Investments - Gas Operations segment.
IPP Investments
- ---------------
During the third quarter of 2003, we initiated an effort to sell four domestic
IPP investments. In accordance with accounting principles generally accepted in
the United States of America, we were required to measure the impairment of each
of these four investments individually. Based on studies using market
assumptions, which indicated that two of the facilities had market values in
excess of book value and two facilities had declines in fair value below book
value that were other than temporary in nature, we recorded an impairment of $70
million pre-tax ($45.5 million net of tax) in the third quarter of 2003. During
the fourth quarter of 2003, we distributed an information memorandum related to
the planned sale of our interest in these IPPs.
In March 2004, we entered into an agreement to sell the four domestic IPP
investments for a sales price of $156 million, subject to closing adjustments.
An additional pre-tax impairment of $1.6 million was recorded in June 2004 to
decrease the carrying value of the Colorado plant investments to their estimated
sales price, less selling expenses. We closed on the sale of the two Florida
investments and the Brush II plant in Colorado in July 2004, resulting in a
pre-tax gain of $104.6 million ($63.8 million, net of tax), generated primarily
from the sale of the two Florida IPPs which were not originally impaired. We
recorded the gain during July 2004. The sale of the Ft. Lupton, Colorado plant
closed in October 2004 and will not have a significant effect on results of
operations for the fourth quarter 2004.
UK Operations
- -------------
In July 2004, we completed the sale of substantially all operations and assets
within our Investments - UK Operations segment for approximately $456 million.
The sale included Fiddler's Ferry, a coal-fired power plant in northwest
England, Ferrybridge, a coal-fired power plant in northeast England, related
coal inventories, and a number of related commodities and freight contracts. The
sale resulted in a pre-tax gain of $265.6 million ($127.6 million, net of tax).
South Coast Power Limited
- -------------------------
In September 2004, we completed the sale of our 50% ownership in South Coast
Power Limited for $46.9 million, resulting in a $47.6 million net gain ($30.9
million, net of tax) in the third quarter 2004. The gain reflects improved
conditions in the U.K. power market.
Other
- -----
We continue to have discussions with various parties on business alternatives
for certain of our other non-core investments, which may result in further
dispositions in the future.
The ultimate timing for a disposition of one or more of these assets will depend
upon market conditions and the value of any buyer's proposal. We believe our
non-core assets are stated at fair value. However, we may realize losses from
operations or losses or gains upon the eventual disposition of these assets
that, in the aggregate, could have a material impact on our results of
operations, cash flows and financial condition.
Texas Regulatory Activity
- -------------------------
Texas Legislation enacted in 1999 provides the framework and timetable to allow
retail electricity competition.
The Texas Legislation, among other things:
o provides for the recovery of generation-related regulatory assets and
other stranded generation costs through securitization and
non-bypassable wires charges,
o requires each utility to structurally unbundle into a retail electric
provider, a power generation company and a transmission and
distribution (T&D) utility,
o provides for an earnings test for each of the years 1999 through 2001 and,
o provides for a stranded cost True-up Proceeding after January 10, 2004.
The True-up Proceedings will determine the amount and recovery of:
o stranded generation plant costs and generation-related regulatory
assets including any unrefunded accumulated excess earnings (net
stranded generation costs),
o carrying charges on true-up-amounts from January 1, 2002 (the commencement
date of retail competition),
o a true-up of actual market prices determined through legislatively-mandated
capacity auctions to the power costs used in the PUCT's excess cost over
market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up),
o final approved deferred fuel balance,
o excess of price-to-beat revenues over market prices subject to certain
conditions and limitations (retail clawback),
o and other true-up items.
TCC's recorded net regulatory asset for amounts subject to approval in the
True-up Proceeding is approximately $1.5 billion at September 30, 2004 of which
$1.3 billion represents net stranded generation costs.
In September 2004, the PUCT held true-up hearings for another utility,
CenterPoint Energy, Inc. (CenterPoint). In that case the PUCT is expected to
issue an order later in November 2004 addressing numerous items and that
decision may provide indications of possible PUCT actions in TCC's true-up
proceedings including:
o the methodology for calculating the recoverable carrying cost related to the
True-up Proceedings,
o whether to and how to modify the calculation of the wholesale capacity
auction true-up, and
o whether the amount of depreciation in the ECOM model on generation assets
for 2002 and 2003 used to calculate the wholesale capacity auction true-up
is a recovery of net stranded generation costs and should reduce the
recoverable cost. The total TCC depreciation in the ECOM model for the
2002-2003 period was $238 million.
When TCC's True-up Proceeding is completed, TCC currently intends to file to
recover PUCT-approved net stranded generation costs and other recoverable
true-up amounts that are in excess of current securitized amounts, plus
appropriate carrying charges, through a non-bypassable competition transition
charge in the regulated T&D rates. TCC may seek to securitize the approved net
stranded generation costs plus related carrying costs. The annual costs of
securitization are recoverable through a non-bypassable transition charge
collected by the T&D utility over the term of the securitization bonds.
TCC will seek to recover in the True-up Proceeding an amount in excess of the
$1.5 billion recorded net true-up regulatory asset through September 30, 2004.
This is primarily due to TCC not having accrued a carrying cost on its net
regulatory asset due to litigation and uncertainties associated with the
treatment and measurement of such amounts by the PUCT. Management expects that
its review of the final order in the CenterPoint case will resolve numerous
uncertainties about applicable PUCT positions and that TCC will be able to
record a carrying cost in the fourth quarter of 2004.
Due to the preliminary nature of the pending CenterPoint proceedings and the
consequent uncertainty, differences between CenterPoint's and TCC's facts and
circumstances and the lack of direct applicability of the CenterPoint proceeding
to TCC's recorded assets, we cannot, at this time, determine whether
disallowances that may be applicable to CenterPoint would be applicable to TCC.
We believe that our recorded regulatory assets are in compliance with Texas
Legislation and we intend to seek vigorously recovery of all of these amounts.
If, however, we determine that it is probable TCC cannot recover a portion of
its recorded net true-up regulatory asset of $1.5 billion, and we are able to
estimate the amount of such non-recovery, we will record a provision for such
amount which could have a material adverse effect on future results of
operations, cash flows and possible financial condition. To the extent decisions
in the TCC True-up Proceeding differ from management expectations based in part
on our evaluation of the final CenterPoint decision, additional material
disallowances are possible.
In another matter before the PUCT, TCC has filed for an adjusted $41 million
base rate increase in its retail distribution rates. After hearing the case the
ALJ has recommended a reduction in existing rates of somewhere between $33
million and $43 million depending on the final treatment of consolidated tax
savings and other remanded issues. We defended vigorously the Company's
requested increase and challenged the ALJ's recommendation in a brief. Hearings
were held on the consolidated tax savings remand issue in September 2004. The
PUCT is expected to issue a decision in the fourth quarter of 2004.
See Notes 3 and 4 for further discussion of Texas Regulatory Activity.
Ohio Regulatory Activity
- ------------------------
The Ohio Electric Restructuring Act of 1999 (Ohio Act) provides for a Market
Development Period (MDP) during which retail customers can choose their electric
power suppliers or receive Default Service at frozen generation rates from the
incumbent utility. After the end of the MDP, January 1, 2006, customers were
scheduled to move to market prices for the supply of electricity.
The PUCO invited default service providers to propose an alternative to all
customers moving to market prices on January 1, 2006. On February 9, 2004, CSPCo
and OPCo filed rate stabilization plans with the PUCO addressing prices
following the end of the MDP. If approved by the PUCO, prices would be
established pursuant to CSPCo's and OPCo's plans for the period from January 1,
2006 through December 31, 2008. The plans are intended to provide price
stability and certainty for customers, facilitate the development of a
competitive retail market in Ohio, provide recovery of environmental, RTO costs
and other costs during the plan period and improve the environmental performance
of AEP's generation resources that serve Ohio customers. The plans include
annual, fixed increases in the generation component of all customers' bills (3%
annually for CSPCo and 7% annually for OPCo) in 2006, 2007 and 2008 and the
opportunity for additional generation-related increases upon PUCO review and
approval. Our Ohio Companies Rate Stabilization Plans also provide for the
deferral of environmental construction and in-service carrying costs plus PJM
RTO administrative fees in 2004 and 2005 for recovery through wires charges in
2006 through 2008. A non-affiliated utility received an order which rejected its
request for automatic increases and cost deferrals during the MDP period. The
PUCO has indicated in FirstEnergy companies' rate stabilization plans that these
plans are specific to a company's requirements and characteristics and the
PUCO's order in one case should not be considered a precedent for the plan of
another company's rate stabilization plan. Management cannot predict whether
CSPCo's and OPCo's plans will be approved as submitted nor can we predict the
ultimate impact these proceedings will have on revenues, results of operations
and cash flows. See Note 4 for further discussion of Ohio Regulatory Activity.
Oklahoma Regulatory Activity
- ----------------------------
PSO filed with the Corporation Commission of the State of Oklahoma (OCC) for
recovery of a $44 million under-recovery of fuel costs resulting from a
reallocation among AEP West electric operating companies of purchased power
costs for periods prior to January 1, 2002. The OCC has expanded the case to
include a full review of PSO's 2001 fuel and purchased power practices.
Intervenor and OCC Staff filings in the case recommended a disallowance of $18
million associated with the allocation of off-system sales margins. At a June
2004 prehearing conference, PSO questioned whether the issues in dispute were
under the jurisdiction of the OCC because they relate to FERC-approved
allocation agreements. As a result, the ALJ ordered that the parties brief the
jurisdictional issue. PSO filed its brief on September 1, 2004. Subject to the
OCC's decision as to jurisdiction, a hearing date has been set for January 2005.
Management believes that fuel costs have been prudently incurred consistent with
OCC rules, and that the allocation of off-system sales margins was made pursuant
to the FERC-approved allocation agreements. If the OCC determines that a portion
of PSO's unrecovered fuel and purchased power costs should not be recovered,
there will be, subject to the FERC jurisdictional question, an adverse effect on
PSO's results of operations, cash flows and possibly financial condition.
In February 2003, the OCC filed an application requiring PSO to file all
documents necessary for a general rate review. In October 2003 and June 2004,
PSO filed financial information and supporting testimony in response to the
OCC's requirements. PSO's response indicates that its annual revenues are $41
million less than costs. As a result, PSO is seeking OCC approval to increase
its base rates by that amount, which is a 3.9% increase over PSO's existing
revenues. A decision is not expected until second quarter 2005. Management is
unable to predict the ultimate effect of these proceedings on PSO's revenues,
results of operations, cash flows and financial condition.
FERC Order on Regional Through and Out Rates
- --------------------------------------------
In July 2003, the FERC issued an order directing PJM and the Midwest Independent
System Operator (ISO) to make compliance filings for their respective OATTs to
eliminate the transaction-based charges for through and out (T&O) transmission
service on transactions where the energy is delivered within the proposed
Midwest ISO and PJM expanded regions (Combined Footprint). The elimination of
the T&O rates will reduce the transmission service revenues collected by the
RTOs and thereby reduce the revenues received by transmission owners under the
RTOs' revenue distribution protocols.
AEP and several other utilities in the Combined Footprint have filed a proposal
for new rates to become effective December 1, 2004. The AEP East companies
received approximately $157 million of T&O rate revenues for the twelve months
ended December 31, 2003. At this time, management is unable to predict whether
the rate design approved by the FERC will fully compensate the AEP East
companies for their lost T&O revenues and whether any resultant increase in
rates applicable to AEP's internal load will be recoverable on a timely basis
from state retail customers. Unless new replacement rates compensate AEP for its
lost revenues and any increase in AEP East Companies' transmission expenses from
these new rates are fully recovered in retail rates on a timely basis, future
results of operations, cash flows and financial condition will be adversely
affected.
Other Regulatory Activity
- -------------------------
There are other significant regulatory risks not included above. See notes 3 and
4 for further discussions of these risks.
RTO Formation
- -------------
The FERC's AEP-CSW merger approval and many of the settlement agreements with
the state regulatory commissions to approve the AEP-CSW merger required the
transfer of functional control of our subsidiaries' transmission systems to
RTOs. In addition, legislation in some of our states requires RTO participation.
Our AEP East companies joined PJM RTO on October 1, 2004. To minimize the credit
requirements and operating constraints when joining PJM, the AEP East Companies
as well as Wheeling Power Company and Kingsport Power Company, have agreed to a
netting of all payment obligations incurred by any of the AEP East companies
against all balances due the AEP East companies, and to hold PJM harmless from
actions that any one or more AEP East companies may take with respect to PJM.
AEP West companies are members of ERCOT or SPP. In February 2004, the FERC
granted RTO status to the SPP, subject to fulfilling specified requirements. In
October 2004, the FERC issued an order granting final RTO status to SPP subject
to certain filings. Regulatory activities concerning various RTO issues are
ongoing in Arkansas and Louisiana.
Litigation
- ----------
We continue to be involved in various litigation matters as described in the
"Significant Factors - Litigation" section of Management's Financial Discussion
and Analysis of Results of Operations in our 2003 Annual Report. The 2003 Annual
Report should be read in conjunction with this report in order to understand
other litigation matters that did not have significant changes in status since
the issuance of our 2003 Annual Report, but may have a material impact on our
future results of operations, cash flows and financial condition. Other matters
described in the 2003 Annual Report that did not have significant changes during
the first nine months of 2004, that should be read in order to gain a full
understanding of our current litigation include: (1) Bank of Montreal Claim, and
(2) Potential Uninsured Losses.
Federal EPA Complaint and Notice of Violation
- ---------------------------------------------
See discussion of New Source Review Litigation within "Significant Factors -
Environmental Matters."
Enron Bankruptcy
- ----------------
In 2002, certain of our subsidiaries filed claims against Enron and its
subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy
Court for the Southern District of New York. At the date of Enron's bankruptcy,
certain of our subsidiaries had open trading contracts and tradi