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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 trading accounts
receivables and payables with Enron. In addition, on June 1, 2001, we purchased
HPL from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.
Enron Bankruptcy - Bammel storage facility and HPL indemnification matters - In
connection with the 2001 acquisition of HPL, we entered into a prepaid
arrangement under which we acquired exclusive rights to use and operate the
underground Bammel gas storage facility and appurtenant pipelines pursuant to an
agreement with BAM Lease Company. This exclusive right to use the referenced
facility is for a term of 30 years, with a renewal right for another 20 years.
In January 2004, we filed an amended lawsuit against Enron and its subsidiaries
in the U.S. Bankruptcy Court claiming that Enron did not have the right to
reject the Bammel storage facility agreement or the cushion gas use agreement,
described below. In April 2004, AEP and Enron entered into a settlement
agreement under which we will acquire title to the Bammel gas storage facility
and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF)
of natural gas currently used as cushion gas for $115 million. AEP and Enron
will mutually release each other from all claims associated with the Bammel
facility, including our indemnity claims. The settlement received Bankruptcy
Court approval on September 30, 2004 and is expected to close in the fourth
quarter 2004. The parties' respective trading claims and Bank of America's (BOA)
purported lien on approximately 55 BCF of natural gas in the Bammel storage
reservoir (as described below) are not covered by the settlement agreement.
Enron Bankruptcy - Right to use of cushion gas agreements - In connection with
the 2001 acquisition of HPL, we also entered into an agreement with BAM Lease
Company, which grants HPL the exclusive right to use approximately 65 BCF of
cushion gas (the 10.5 BCF and 55 BCF described in the preceding paragraph)
required for the normal operation of the Bammel gas storage facility. At the
time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate)
and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of
cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate
also released HPL from all prior and future liabilities and obligations in
connection with the financing arrangement.
After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported
default by Enron under the terms of the financing arrangement. In July 2002, the
BOA Syndicate filed a lawsuit against HPL in the state court of Texas seeking a
declaratory judgment that the BOA Syndicate has a valid and enforceable security
interest in gas purportedly in the Bammel storage reservoir. In December 2003,
the Texas state court granted partial summary judgment in favor of the BOA
Syndicate. HPL appealed this decision. In June 2004, BOA filed an amended
petition in a separate lawsuit in Texas state court seeking to obtain possession
of up to 55 BCF of storage gas in the Bammel storage facility or its fair value.
Following an adverse decision on its motion to obtain possession of this gas,
BOA voluntarily dismissed this action. In October 2004, BOA refiled this action.
HPL filed a motion to have the case assigned to the judge who heard the case
originally and that motion was granted. HPL intends to defend vigorously against
BOA's claims.
In October 2003, AEP filed a lawsuit against BOA in the United States District
Court for the Southern District of Texas. BOA led a lending syndicate involving
the 1997 gas monetization that Enron and its subsidiaries undertook and the
leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit
asserts that BOA made misrepresentations and engaged in fraud to induce and
promote the stock sale of HPL, that BOA directly benefited from the sale of HPL
and that AEP undertook the stock purchase and entered into the Bammel storage
facility lease arrangement with Enron and the cushion gas arrangement with Enron
and BOA based on misrepresentations that BOA made about Enron's financial
condition that BOA knew or should have known were false including that the 1997
gas monetization did not contravene or constitute a default of any federal,
state, or local statute, rule, regulation, code or any law. In February 2004,
BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the
Magistrate Judge issued a Recommended Decision and Order recommending that BOA's
Motion to Dismiss be denied, that the five counts in the lawsuit seeking
declaratory judgments involving the Bammel reservoir and the right to use and
cushion gas consent agreements be transferred to the Southern District of New
York and that the four counts alleging breach of contract, fraud and negligent
misrepresentation proceed in the Southern District of Texas. BOA has objected to
the Magistrate Judge's decision and the matter is now before the District Judge.
In February 2004, in connection with BOA's dispute, Enron filed Notices of
Rejection regarding the cushion gas exclusive right to use agreement and other
incidental agreements. We have objected to Enron's attempted rejection of these
agreements.
Enron Bankruptcy - Commodity trading settlement disputes - In September 2003,
Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP's
offsetting of receivables and payables and related collateral across various
Enron entities and seeking payment of approximately $125 million plus interest
in connection with gas related trading transactions. AEP has asserted its right
to offset trading payables owed to various Enron entities against trading
receivables due to several AEP subsidiaries. The parties are currently in
non-binding court-sponsored mediation.
In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC
seeking approximately $93 million plus interest in connection with a transaction
for the sale and purchase of physical power among Enron, AEP and Allegheny
Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the
effects of the transaction. AEP believes it has several defenses to the claims
in the action being brought by Enron. The parties are currently in non-binding
court-sponsored mediation.
Enron Bankruptcy - Summary - The amount expensed in prior years in connection
with the Enron bankruptcy was based on an analysis of contracts where AEP and
Enron entities are counterparties, the offsetting of receivables and payables,
the application of deposits from Enron entities and management's analysis of the
HPL-related purchase contingencies and indemnifications. As noted above, Enron
has challenged our offsetting of receivables and payables and there is a dispute
regarding the cushion gas agreement. Although management is unable to predict
the outcome of these lawsuits, it is possible that their resolution could have
an adverse impact on our results of operations, cash flows or financial
condition.
Merger Litigation
- -----------------
In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the
SEC failed to adequately explain that the June 15, 2000 merger of AEP with CSW
meets the requirements of the PUHCA and sent the case back to the SEC for
further review. Specifically, the court told the SEC to revisit the basis for
its conclusion that the merger met PUHCA requirements that utilities be
"physically interconnected" and confined to a "single area or region." In August
2004, the SEC announced it would conduct hearings on this issue. The hearing is
scheduled for January 2005.
In its June 2000 approval of the merger, the SEC agreed with AEP that the
companies' systems are integrated because they have transmission access rights
to a single high-voltage line through Missouri and also met the PUHCA's single
region requirement. In its ruling, the appeals court said that the SEC failed to
support and explain its conclusions that the interconnection and single region
requirements are satisfied.
Management believes that the merger meets the requirements of the PUHCA and
expects the matter to be resolved favorably.
Texas Commercial Energy, LLP Lawsuit
- ------------------------------------
Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider (REP),
filed a lawsuit in federal District Court in Corpus Christi, Texas, in July
2003, against us and four of our subsidiaries, certain unaffiliated energy
companies and ERCOT. The action alleges violations of the Sherman Antitrust Act,
fraud, negligent misrepresentation, breach of fiduciary duty, breach of
contract, civil conspiracy and negligence. The allegations, not all of which are
made against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price spikes
requiring TCE to post additional collateral and ultimately forced it into
bankruptcy when it was unable to raise prices to its customers due to fixed
price contracts. The suit alleges over $500 million in damages for all
defendants and seeks recovery of damages, exemplary damages and court costs. Two
additional parties, Utility Choice, LLC and Cirro Energy Corporation, have
sought leave to intervene as plaintiffs asserting similar claims. We filed a
Motion to Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. We filed a Motion to Dismiss the amended complaint. In June 2004, the
Court dismissed all claims against the AEP companies. TCE has appealed the trial
court's decision to the United States Court of Appeals for the Fifth Circuit.
Energy Market Investigations
- ----------------------------
AEP and other energy market participants received data requests, subpoenas and
requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity
Futures Trading Commission (CFTC), the U.S. Department of Justice and the
California attorney general during 2002. Management responded to the inquiries
and provided the requested information and has continued to respond to
supplemental data requests in 2003 and 2004.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in
federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES
provided false or misleading information about market conditions and prices of
natural gas in an attempt to manipulate the price of natural gas in violation of
the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and
disgorgement of benefits. We responded to the complaint in September 2004. In
2003 we recorded a provision related to these matters. We have engaged in
settlement discussions with several agencies and are evaluating whether to
conclude settlements in order to put these investigations behind us even though
we believe we have meritorious legal positions and defenses. If we elect to
settle all matters, the payments could exceed the 2003 provision and could have
a material impact on our 2004 earnings and cash flows.
Shareholders' Litigation
- ------------------------
In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against us, certain
AEP executives, members of the Board of Directors and certain investment banking
firms. Certain of these actions were dismissed in September 2004. We intend to
defend vigorously against the remaining actions. See Note 5 for further
discussion.
Cornerstone Lawsuit
- -------------------
In the third quarter of 2003, Cornerstone Propane Partners filed an action in
the United States District Court for the Southern District of New York against
forty companies, including AEP and AEPES seeking class certification and
alleging unspecified damages from claimed price manipulation of natural gas
futures and options on the NYMEX from January 2000 through December 2002.
Thereafter, two similar actions were filed in the same court against a number of
companies including AEP and AEPES making essentially the same claims as
Cornerstone Propane Partners and also seeking class certification. On December
5, 2003, the Court issued its initial Pretrial Order consolidating all related
cases, appointing co-lead counsel and providing for the filing of an amended
consolidated complaint. In January 2004, plaintiffs filed an amended
consolidated complaint. We and the other defendants filed a motion to dismiss
the complaint which the Court denied in September 2004. We intend to defend
vigorously against these claims.
SWEPCo Notice of Enforcement and Notice of Citizen Suit
- -------------------------------------------------------
On July 13, 2004, two special interest groups issued a notice of intent to
commence a citizen suit under the Clean Air Act for alleged violations of
various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and
Pirkey plants. This notice was prompted by allegations made by a terminated AEP
employee. The allegations at the Welsh Plant concern compliance with emission
limitations on particulate matter and carbon monoxide, compliance with a
referenced design heat input value, and compliance with certain reporting
requirements. The allegations at the Knox Lee Plant relate to the receipt of an
off-specification fuel oil, and the allegations at Pirkey Plant relate to
testing and reporting of volatile organic compound emissions. No action can be
commenced until 60 days after the date of notice.
On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a
Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary
of findings resulting from a compliance investigation at the plant. The summary
includes allegations concerning compliance with certain recordkeeping and
reporting requirements, compliance with a referenced design heat input value in
the Welsh permit, compliance with a fuel sulfur content limit, and compliance
with emission limits for sulfur dioxide.
On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to
the off-specification fuel oil deliveries at the Knox Lee Plant. On August 30,
2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the reporting of
volatile organic compound emissions at the Pirkey Plant.
SWEPCo has previously reported to the TCEQ, deviations related to the receipt of
off-specification fuel at Knox Lee, the volatile organic compound emissions at
Pirkey, and the referenced recordkeeping and reporting requirements and heat
input value at Welsh. We are preparing additional responses to the Notice of
Enforcement and the notice from the special interest groups. Management is
unable to predict the timing of any future action by TCEQ or the special
interest groups or the effect of such actions on results of operations, cash
flows or financial condition.
Carbon Dioxide Public Nuisance Claims
- -------------------------------------
On July 21, 2004, attorneys general from eight states and the corporation
counsel for the City of New York filed an action in federal district court for
the Southern District of New York against AEP, AEPSC and four other unaffiliated
governmental and investor-owned electric utility systems. That same day, a
similar complaint was filed in the same court against the same defendants by the
Natural Resources Defense Council on behalf of three special interest groups.
The actions allege that carbon dioxide emissions from power generation
facilities constitute a public nuisance under federal common law due to impacts
associated with global warming, and seek injunctive relief in the form of
specific emission reduction commitments from the defendants. In September 2004,
the defendants, including AEP and AEPSC, filed a motion to dismiss the lawsuits.
Management believes the actions are without merit and intends to defend
vigorously against the claims.
TEM Litigation
- --------------
See discussion of TEM litigation within the "Power Generation Facility" section
of "Financial Condition - Other" within Management's Financial Discussion and
Analysis of Results of Operations.
Environmental Matters
- ---------------------
As discussed in our 2003 Annual Report, there are emerging environmental control
requirements that we expect will result in substantial capital investments and
operational costs. The sources of these future requirements include:
o Legislative and regulatory proposals to adopt stringent controls on
sulfur dioxide (SO2), nitrogen oxide (NOx) and mercury emissions from
coal-fired power plants,
o New Clean Water Act rules to reduce the impacts of water intake
structures on aquatic species at certain of our power plants, and
o Possible future requirements to reduce carbon dioxide emissions to address
concerns about global climatic change.
This discussion updates certain events occurring in 2004. You should also read
the "Significant Factors - Environmental Matters" section within Management's
Financial Discussion and Analysis of Results of Operations in our 2003 Annual
Report for a description of all material environmental matters affecting us,
including, but not limited to, (1) the current air quality regulatory framework,
(2) estimated air quality environmental investments, (3) Superfund and state
remediation, (4) global climate change, and (5) costs for spent nuclear fuel
disposal and decommissioning.
Future Reduction Requirements for SO2, NOx and Mercury
- ------------------------------------------------------
In 1997, the Federal EPA adopted new, more stringent national ambient air
quality standards for fine particulate matter and ground-level ozone. The
Federal EPA is in the process of developing final designations for fine
particulate matter non-attainment areas. The Federal EPA finalized designations
for ozone non-attainment areas on April 15, 2004. On the same day, the
Administrator of the Federal EPA signed a final rule establishing the elements
that must be included in state implementation plans (SIPs) to achieve the new
standards, and setting deadlines ranging from 2008 to 2015 for achieving
compliance with the final standard, based on the severity of non-attainment. All
or parts of 474 counties are affected by this new rule, including many urban
areas in the Eastern United States.
The Federal EPA identified SO2 and NOx emissions as precursors to the formation
of fine particulate matter. NOx emissions are also identified as a precursor to
the formation of ground-level ozone. As a result, requirements for future
reductions in emissions of NOx and SO2 from our generating units are highly
probable. In addition, the Federal EPA proposed a set of options for future
mercury controls at coal-fired power plants.
Regulatory Emissions Reductions
- -------------------------------
On January 30, 2004, the Federal EPA published two proposed rules that would
collectively require reductions of approximately 70% each in emissions of SO2,
NOx and mercury from coal-fired electric generating units by 2015 (2018 for
mercury). This initiative has two major components:
o The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce
SO2 and NOx emissions across the eastern half of the United States (29
states and the District of Columbia) and make progress toward
attainment of the new fine particulate matter and ground-level ozone
national ambient air quality standards. These reductions could also
satisfy these states' obligations to make reasonable progress towards
the national visibility goal under the regional haze program.
o The Federal EPA proposed to regulate mercury emissions from coal-fired
electric generating units.
The CAIR would require affected states to include, in their SIPs, a program to
reduce NOx and SO2 emissions from coal-fired electric utility units. SO2 and NOx
emissions would be reduced in two phases, which would be implemented through a
cap-and-trade program. Regional SO2 emissions would be reduced to 3.9 million
tons by 2010 and to 2.7 million tons by 2015. Regional NOx emissions would be
reduced to 1.6 million tons by 2010 and to 1.3 million tons by 2015. Rules to
implement the SO2 and NOx trading programs were proposed on June 10, 2004.
On April 15, 2004, the Federal EPA Administrator signed a proposed rule
detailing how states should analyze and include "Best Available Retrofit"
requirements for individual facilities in their SIPs to address regional haze.
The guidance applies to facilities built between 1962 and 1977 that emit more
than 250 tons per year of certain regulated pollutants in specific industrial
categories, including utility boilers. The Federal EPA included an alternative
"Best Available Retrofit" program based on emissions budgeting and trading
programs. For utility units that are affected by the CAIR, described above, the
Federal EPA proposed that participation in the trading program under the CAIR
would satisfy any applicable "Best Available Retrofit" requirements. However,
the guidance preserves the ability of a state to require site-specific
installation of pollution control equipment through the SIP for purposes of
abating regional haze.
To control and reduce mercury emissions, the Federal EPA published two
alternative proposals. The first option requires the installation of maximum
achievable control technology (MACT) on a site-specific basis. Mercury emissions
would be reduced from 48 tons to approximately 34 tons by 2008. The Federal EPA
believes, and the industry concurs, that there are no commercially available
mercury control technologies in the marketplace today that can achieve the MACT
standards for bituminous coals, but certain units have achieved comparable
levels of mercury reduction by installing conventional SO2 (scrubbers) and NOx
(SCR) emission reduction technologies. The proposed rule imposes significantly
less stringent standards on generating plants that burn sub-bituminous coal or
lignite. The proposed standards for sub-bituminous coals potentially could be
met without installation of mercury control technologies.
The Federal EPA recommends, and we support, a second mercury emission reduction
option. The second option would permit mercury emission reductions to be
achieved from existing sources through a national cap-and-trade approach. The
cap-and-trade approach would include a two-phase mercury reduction program for
coal-fired utilities. This approach would coordinate the reduction requirements
for mercury with the SO2 and NOx reduction requirements imposed on the same
sources under the CAIR. Coordination is significantly more cost-effective
because technologies like scrubbers and SCRs, which can be used to comply with
the more stringent SO2 and NOx requirements, have also proven effective in
reducing mercury emissions on certain coal-fired units that burn bituminous
coal. The second option contemplates reducing mercury emissions from 48 tons to
34 tons by 2010 and to 15 tons by 2018. A supplemental proposal including
unit-specific allocations and a framework for the emissions budgeting and
trading program preferred by the Federal EPA was published in the Federal
Register on March 16, 2004. We filed comments on both the initial proposal and
the supplemental notice in June 2004.
The Federal EPA's proposals are the beginning of a lengthy rulemaking process,
which will involve supplemental proposals on many details of the new regulatory
programs, written comments and public hearings, issuance of final rules, and
potential litigation. In addition, states have substantial discretion in
developing their rules to implement cap-and-trade programs, and will have 18
months after publication of the notice of final rulemaking to submit their
revised SIPs. As a result, the ultimate requirements may not be known for
several years and may depart significantly from the original proposed rules
described here.
While uncertainty remains as to whether future emission reduction requirements
will result from new legislation or regulation, it is certain under either
outcome that we will invest in additional conventional pollution control
technology on a major portion of our fleet of coal-fired power plants.
Finalization of new requirements for further SO2, NOx and/or mercury emission
reductions will result in the installation of additional scrubbers, SCR systems
and/or the installation of emerging technologies for mercury control. The cost
of such facilities could have an adverse effect on future results of operations,
cash flows and financial condition unless recovered from customers.
New Source Review Litigation
- ----------------------------
Under the Clean Air Act (CAA), if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed components, or other
repairs needed for the reliable, safe and efficient operation of the plant.
The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and
other unaffiliated utilities modified certain units at coal-fired generating
plants in violation of the new source review requirements of the CAA. The
Federal EPA filed its complaints against our subsidiaries in U.S. District Court
for the Southern District of Ohio. The court also consolidated a separate
lawsuit, initiated by certain special interest groups, with the Federal EPA
case. The alleged modifications relate to costs that were incurred at our
generating units over a 20-year period.
On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to
"perfect" its complaint in the pending litigation. The NOV expands the number of
alleged "modifications" undertaken at the Amos, Cardinal, Conesville, Kammer,
Muskingum River, Sporn and Tanners Creek plants during scheduled outages on
these units from 1979 through the present. Approximately one-third of the
allegations in the NOV are already contained in allegations made by the states
or the special interest groups in the pending litigation. The Federal EPA filed
a motion to amend its complaints and to expand the scope of the pending
litigation. The AEP subsidiaries opposed that motion. In September 2004, the
judge disallowed the addition of claims to the pending case. The judge also
granted motions to dismiss a number of allegations in the original filing.
We are unable to estimate the loss or range of loss related to any contingent
liability we might have for civil penalties under the CAA proceedings. We are
also unable to predict the timing of resolution of these matters due to the
number of alleged violations and the significant number of issues yet to be
determined by the Court. If we do not prevail, any capital and operating costs
of additional pollution control equipment that may be required, as well as any
penalties imposed, would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity.
In September 2004, the Sierra Club filed a complaint under the citizen suit
provisions of the CAA in the United States District Court for the Southern
District of Ohio alleging that violations of the PSD and New Source Performance
Standards requirements of the CAA and the opacity provisions of the Ohio state
implementation plan occurred at the J.M. Stuart Station, and seeking injunctive
relief and civil penalties. Stuart Station is jointly owned by CSPCo (26%) and
two unaffiliated utilities. We believe the allegations in the complaint are
without merit, and intend to defend vigorously this action. Management is unable
to predict the timing of any future action by the special interest group or the
effect of such actions on future operations or cash flows.
Clean Water Act Regulation
- --------------------------
On July 9, 2004, the Federal EPA published in the Federal Register a rule
pursuant to the Clean Water Act that will require all large existing,
once-through cooled power plants to meet certain performance standards to reduce
the mortality of juvenile and adult fish or other larger organisms pinned
against a plant's cooling water intake screens. All plants must reduce fish
mortality by 80% to 95%. A subset of these plants that are located on sensitive
water bodies will be required to meet additional performance standards for
reducing the number of smaller organisms passing through the water screens and
the cooling system. These plants must reduce the rate of smaller organisms
passing through the plant by 60% to 90%. Sensitive water bodies are defined as
oceans, estuaries, the Great Lakes, and small rivers with large plants. These
rules will result in additional capital and operation and maintenance expenses
to ensure compliance. The estimated capital cost of compliance for our
facilities, based on the Federal EPA's analysis in the rule, is $193 million.
Any capital costs associated with compliance activities to meet the new
performance standards would likely be incurred during the years 2008 through
2010. We have not independently confirmed the accuracy of the Federal EPA's
estimate. The rule has provisions to limit compliance costs. We may propose less
costly site-specific performance criteria if our compliance cost estimates are
significantly greater than the Federal EPA's estimates or greater than the
environmental benefits. The rule also allows us to propose mitigation (also
called restoration measures) that is less costly and has equivalent or superior
environmental benefits than meeting the criteria in whole or in part. Several
states, electric utilities (including our APCo subsidiary) and environmental
groups appealed certain aspects of the rule. We cannot predict the outcome of
the appeals.
Spent Nuclear Fuel Disposal
- ---------------------------
As a result of DOE's failure to make sufficient progress toward a permanent
repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and
STP Nuclear Operating Company on behalf of TCC and the other STP owners, along
with a number of unaffiliated utilities and states, filed suit in the D.C.
Circuit Court requesting, among other things, that the D.C. Circuit Court order
DOE to meet its obligations under the law. The D.C. Circuit Court ordered the
parties to proceed with contractual remedies but declined to order DOE to begin
accepting SNF for disposal. DOE estimates its planned site for the nuclear waste
will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in
the U.S. Court of Federal Claims seeking damages in excess of $150 million due
to the DOE's partial material breach of its unconditional contractual deadline
to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were
filed by other utilities. In August 2000, in an appeal of related cases
involving other unaffiliated utilities, the U.S. Court of Appeals for the
Federal Circuit held that the delays clause of the standard contract between
utilities and the DOE did not apply to DOE's complete failure to perform its
contract obligations, and that the utilities' suits against DOE may continue in
court. On January 17, 2003, the U.S. Court of Federal Claims ruled in favor of
I&M on the issue of liability. The case continued on the issue of damages owed
to I&M by the DOE. In May 2004, the U.S. Court of Federal Claims ruled against
I&M and denied damages. In July 2004, I&M appealed this ruling to the U.S. Court
of Appeals for the Federal Circuit. As long as the delay in the availability of
a government approved storage repository for SNF continues, the cost of both
temporary and permanent storage of SNF and the cost of decommissioning will
continue to increase. If such cost increases are not recovered on a timely basis
in regulated rates, future results of operations and cash flows could be
adversely affected.
Nuclear Decommissioning
- -----------------------
As discussed in the 2003 Annual Report, decommissioning costs are accrued over
the service life of STP. The licenses to operate the two nuclear units at STP
expire in 2027 and 2028. TCC had estimated its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of approximately $8 million per year.
In May 2004, an updated decommissioning study was completed for STP. The study
estimates TCC's share of the decommissioning costs of STP to be $344 million in
nondiscounted 2004 dollars. We are currently analyzing the STP study to
determine the effect on our asset retirement obligations (ARO) and will make any
appropriate adjustments to the ARO liability and related regulatory asset in the
fourth quarter 2004. TCC is in the process of selling its ownership interest in
STP to a non-affiliate, and upon completion of the sale it is anticipated that
TCC will no longer be obligated for nuclear decommissioning liabilities
associated with STP.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Management's Financial Discussion and
Analysis of Results of Operations" in the 2003 Annual Report for a discussion of
the estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
Other Matters
- -------------
As discussed in our 2003 Annual Report, there are several "Other Matters"
affecting us. The current status of FERC's market power mitigation efforts is
described below.
FERC Market Power Mitigation
- ----------------------------
In April 2004, the FERC issued two orders concerning utilities' ability to sell
wholesale electricity at market-based rates. In the first order, the FERC
adopted two new interim screens for assessing potential generation market power
of applicants for wholesale market based rates, and described additional
analyses and mitigation measures that could be presented if an applicant does
not pass one of these interim screens. These two screening tests include a
"pivotal supplier" test which determines if the market load can be fully served
by alternative suppliers and a "market share" test which compares the amount of
surplus generation at the time of the applicant's minimum load. In July 2004,
the FERC issued an order on rehearing affirming its conclusions in the April
order and directing AEP and two unaffiliated utilities to file generation market
power analyses within 30 days. In the second order, the FERC initiated a
rulemaking to consider whether the FERC's current methodology for determining
whether a public utility should be allowed to sell wholesale electricity at
market-based rates should be modified in any way.
On August 9, 2004, AEP submitted its Market Power Analysis pursuant to the
FERC's Orders on Rehearing. The analysis focused on the three major areas in
which AEP serves load and owns generation resources, ECAR, SPP and ERCOT, and
the "first tier" control areas for each of those areas.
The pivotal supplier and market share screen analyses that AEP filed
demonstrated that AEP does not possess market power in any of the control areas
to which it is directly connected (first-tier markets). AEP passed both
screening tests in all of its "first tier" markets. In its three "home" control
areas, AEP easily passed the pivotal supplier test. AEP, as part of PJM, also
passes the market share screen for the PJM destination market. AEP also passed
the market share screen for ERCOT. AEP did not pass the market share screen as
designed by the FERC for the SPP control area. Consequently, AEP also submitted
substantial additional information, including historical purchase and sales data
that demonstrates that AEP does not possess market power in any of the "home"
destination markets. AEP requested that its existing market-based pricing
authorization in all markets be continued based on this analysis. AEP also
requested that the FERC rule without instituting a proceeding and without
setting a refund date. This case is pending.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
As a major power producer and marketer of wholesale electricity and natural gas,
we have certain market risks inherent in our business activities. These risks
include commodity price risk, interest rate risk, foreign exchange risk and
credit risk. They represent the risk of loss that may impact us due to changes
in the underlying market prices or rates.
We have established policies and procedures that allow us to identify, assess,
and manage market risk exposures in our day-to-day operations. Our risk policies
have been reviewed with our Board of Directors and approved by our Risk
Executive Committee. Our Chief Risk Officer administers our risk policies and
procedures. The Risk Executive Committee establishes risk limits, approves risk
policies, and assigns responsibilities regarding the oversight and management of
risk and monitors risk levels. Members of this committee receive daily, weekly,
and monthly reports regarding compliance with policies, limits and procedures.
Our committee meets monthly and consists of the Chief Risk Officer, Credit Risk
Management, Market Risk Oversight, and senior financial and operating managers.
We actively participate in the Committee of Chief Risk Officers (CCRO) to
develop standard disclosures for risk management activities around risk
management contracts. The CCRO is composed of the chief risk officers of major
electricity and gas companies in the United States. The CCRO adopted disclosure
standards for risk management contracts to improve clarity, understanding and
consistency of information reported. Implementation of the disclosures is
voluntary. We support the work of the CCRO and have embraced the disclosure
standards. The following tables provide information on our risk management
activities.
Mark-to-Market Risk Management Contract Net Assets (Liabilities)
- ----------------------------------------------------------------
This table provides detail on changes in our mark-to-market (MTM) net asset or
liability balance sheet position from one period to the next.
MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2004
Investments Investments
Utility Gas UK
Operations Operations Operations (i) Consolidated
---------- ---------- -------------- ------------
(in millions)
Total MTM Risk Management Contract Net Assets
(Liabilities) at December 31, 2003 $286 $5 $(246) $45
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (108) (37) 254 109
Fair Value of New Contracts When Entered
Into During the Period (b) - - - -
Net Option Premiums Paid/(Received) (c) (1) 3 - 2
Change in Fair Value Due to Valuation Methodology
Changes (d) 3 - - 3
Changes in Fair Value of Risk Management
Contracts (e) 61 (6) (10) 45
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (f)
(3) - - (3)
----- ----- ------ -----
Total MTM Risk Management Contract
Net Assets (Liabilities) at September 30, 2004 $238 $(35) $(2) 201
===== ===== ====== -----
Net Cash Flow Hedge Contracts (g) (152)
Net Risk Management Liabilities
Held for Sale, included in the totals above (h) 2
-----
Ending Net Risk Management Assets at September 30, 2004
$51
=====
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 and were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value at inception of long-term
contracts entered into with customers during 2004. Most of the fair
value comes from longer term fixed price contracts with customers
that seek to limit their risk against fluctuating energy prices. The
contract prices are valued against market curves associated with the
delivery location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
storage, etc.
(f) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Operations. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed in detail
within the following pages.
(h) See Note 7 for discussion of Assets Held for Sale.
(i) During 2004, we began to unwind our risk management contracts within the
U.K. as part of our planned divestiture of our UK Operations. We
completed the sale of substantially all of our operations and assets in
the Investments-UK Operations segment in July 2004.
Detail on MTM Risk Management Contract Net Assets (Liabilities)
As of September 30, 2004
Investments
Utility Gas
Operations Operations Consolidated
---------- ----------- ------------
(in millions)
Current Assets $590 $208 $798
Non Current Assets 382 143 525
----- ----- -------
Total Assets 972 351 1,323
----- ----- -------
Current Liabilities (521) (224) (745)
Non Current Liabilities (213) (162) (375)
----- ----- -------
Total Liabilities (734) (386) (1,120)
----- ----- -------
Total Net Assets (Liabilities),
excluding Cash Flow Hedges $238 $(35) $203
===== ===== =======
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of September 30, 2004
MTM Risk PLUS:
Management Cash Flow
Contracts(a) Hedges Consolidated (b)
------------ --------- ----------------
(in millions)
Current Assets $798 $12 $810
Non Current Assets 525 2 527
------- ------ -------
Total MTM Derivative
Contract Assets 1,323 14 1,337
------- ------ -------
Current Liabilities (745) (158) (903)
Non Current Liabilities (375) (8) (383)
------- ------ -------
Total MTM Derivative
Contract Liabilities (1,120) (166) (1,286)
------- ------ -------
Total MTM Derivative
Contract Net Assets
(Liabilities) $203 $(152) $51
======= ====== =======
(a) Does not include Cash Flow Hedges and Assets Held for Sale.
(b) Represents amount of total MTM derivative contracts recorded within
Risk Management Assets, Long-term Risk Management Assets, Risk
Management Liabilities and Long-term Risk Management Liabilities on our
Consolidated Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract
Net Assets (Liabilities)
- -----------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets (liabilities) provides two fundamental pieces of
information.
o The source of fair value used in determining the carrying amount
of our total MTM asset or liability (external sources or modeled
internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities)
Fair Value of Contracts as of September 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 (c) Total (d)
--------- ---- ---- ---- ---- -------- ---------
(in millions)
Utility Operations:
- -------------------
Prices Actively Quoted - Exchange
Traded Contracts $- $(76) $2 $8 $- $- $(66)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 4 142 19 7 - - 172
Prices Based on Models and Other
Valuation Methods (b) 3 11 13 26 25 54 132
----- ----- ---- ----- ---- ---- -----
Total 7 77 34 41 25 54 238
----- ----- ---- ----- ---- ---- -----
Investments - Gas Operations:
- -----------------------------
Prices Actively Quoted - Exchange
Traded Contracts 13 82 (3) 2 - - 94
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (55) (56) - - - - (111)
Prices Based on Models and Other
Valuation Methods (b) - 2 (8) (4) (3) (5) (18)
----- ----- ---- ----- ---- ---- -----
Total (42) 28 (11) (2) (3) (5) (35)
----- ----- ---- ----- ---- ---- -----
Investments - UK Operations (e):
- --------------------------------
Prices Actively Quoted - Exchange
Traded Contracts - - - - - - -
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 4 (8) (1) - - - (5)
Prices Based on Models and Other
Valuation Methods (b) 3 - - - - 3
----- ----- ---- ----- ---- ---- -----
Total 7 (8) (1) - - (2)
----- ----- ---- ----- ---- ---- -----
Consolidated:
- -------------
Prices Actively Quoted - Exchange
Traded Contracts 13 6 (1) 10 - - 28
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (47) 78 18 7 - - 56
Prices Based on Models and Other
Valuation Methods (b) 6 13 5 22 22 49 117
----- ----- ---- ----- ---- ---- -----
Total $(28) $97 $22 $39 $22 $49 $201
===== ===== ==== ===== ==== ==== =====
(a) Prices provided by other external sources - Reflects information obtained from over-the-counter brokers, industry services, or
multiple-party on-line platforms.
(b) Modeled - In the absence of pricing information from external sources, modeled information is derived using valuation models
developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation
adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available
from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are
classified as modeled.
(c) There is $20 million of mark-to-market value in 2009 and $19 million of mark-to-market value in 2010.
(d) Amounts exclude Cash Flow Hedges.
(e) The majority of these positions will either mature or be settled with the applicable counterparties during the fourth quarter
2004.
The determination of the point at which a market is no longer liquid for placing
it in the Modeled category in the preceding table varies by market. The
following table reports an estimate of the maximum tenors (contract maturities)
of the liquid portion of each energy market.
Maximum Tenor of the Liquid Portion of Risk Management Contracts
As of September 30, 2004
Domestic Transaction Class Market/Region Tenor
-------- ----------------- ------------- -----
(in months)
Natural Gas Futures NYMEX Henry Hub 63
Physical Forwards Gulf Coast, Texas 18
Swaps Gas East - Northeast, Mid-continent
Gulf Coast, Texas 18
Swaps Gas West - Rocky Mountains,
West Coast 27
Exchange Option Volatility NYMEX/Henry Hub 12
Power Futures PJM 27
Physical Forwards Cinergy 15
Physical Forwards First Energy 21
Physical Forwards PJM 27
Physical Forwards NYPP 27
Physical Forwards NEPOOL 15
Physical Forwards ERCOT 27
Physical Forwards TVA -
Physical Forwards Com Ed 15
Physical Forwards Entergy 9
Physical Forwards PaloVerde 39
Physical Forwards North Path 15, South Path 15 39
Physical Forwards Mid Columbia 39
Peak Power Volatility (Options) Cinergy 12
Peak Power Volatility (Options) PJM 12
Crude Oil Swaps West Texas Intermediate 30
Emissions Credits SO2 51
Coal Physical Forwards PRB, NYMEX, CSX 27
International
-------------
Power Forwards and Options United Kingdom 42
Coal Forward Purchases and Sales United Kingdom -
Swaps Europe 39
Freight Swaps Europe 39
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power and gas operations. We monitor these risks on our future operations and
may employ various commodity instruments and cash flow hedges to mitigate the
impact of these fluctuations on the future cash flows from assets. We do not
hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. International subsidiaries use currency swaps to hedge exchange rate
fluctuations in forecasted foreign currency cashflows. We do not hedge all
foreign currency exposure.
The tables below provide detail on effective cash flow hedges under SFAS 133
included in our balance sheet. The data in the first table will indicate the
magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts
designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge
contracts which are not designated as cash flow hedges are required to be
marked-to-market and are included in the previous risk management tables. This
table further indicates what portions of these hedges are expected to be
reclassified into net income in the next 12 months. The second table provides
the nature of changes from December 31, 2003 to September 30, 2004.
Information on energy merchant activities is presented separately from interest
rate and foreign currency risk management activities. In accordance with
accounting principles generally accepted in the United States of America, all
amounts are presented net of related income taxes.
Cash Flow Hedges included in Accumulated Other Comprehensive Loss
On the Balance Sheet as of September 30, 2004
Portion Expected to
Accumulated Other be Reclassified to
Comprehensive Earnings During the
Loss After Tax (a) Next 12 Months (b)
------------------ -------------------
(in millions)
Power and Gas $(77) $(73)
Foreign Currency - -
Interest Rate (25) (5)
------ -----
Total $(102) $(78)
====== =====
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
Foreign
Power and Gas Currency Interest Rate Consolidated
------------- -------- ------------- ------------
(in millions)
Beginning Balance,
December 31, 2003 $(65) $(20) $(9) $(94)
Changes in Fair Value (c) (73) - (21) (94)
Reclassifications from AOCI to Net
Income (d) 61 20 5 86
----- ----- ----- ------
Ending Balance,
September 30, 2004 $(77) $- $(25) $(102)
===== ===== ===== ======
(a) "Accumulated Other Comprehensive Loss After Tax" - Gains/losses are
net of related income taxes that have not yet been included in the
determination of net income; reported as a separate component of
shareholders' equity on the balance sheet.
(b) "Portion Expected to be Reclassified to Earnings During the Next 12
Months" - Amount of gains or losses (realized or unrealized) from
derivatives used as hedging instruments that have been deferred and
are expected to be reclassified into net income during the next 12
months at the time the hedged transaction affects net income.
(c) "Changes in Fair Value" - Changes in the fair value of derivatives
designated as cash flow hedges not yet reclassified into net income,
pending the hedged items affecting net income. Amounts are reported
net of related income taxes.
(d) "Reclassifications from AOCI to Net Income" - Gains or losses from
derivatives used as hedging instruments in cash flow hedges that were
reclassified into net income during the reporting period. Amounts are
reported net of related income taxes above.
Credit Risk
- -----------
We limit credit risk by assessing creditworthiness of potential counterparties
before entering into transactions with them and continue to evaluate their
creditworthiness after transactions have been initiated. Only after an entity
has met our internal credit rating criteria will we extend unsecured credit. We
use Moody's Investor Service, Standard and Poor's and qualitative and
quantitative data to assess the financial health of counterparties on an ongoing
basis. Our analysis, in conjunction with the rating agencies' information, is
used to determine appropriate risk parameters. We also require cash deposits,
letters of credit and parental/affiliate guarantees as security from
counterparties depending upon credit quality in our normal course of business.
We have risk management contracts with numerous counterparties. Since open risk
management contracts are valued based on changes in market prices of the related
commodities, our exposures change daily. Except for one non-investment grade
counterparty who has a net exposure of approximately $46 million, we believe
that credit exposure with any one counterparty is not material to our financial
condition at September 30, 2004. At September 30, 2004, our credit exposure net
of credit collateral to sub investment grade counterparties was approximately
19% expressed in terms of net MTM assets and net receivables. The concentration
in non-investment grade credit exposure is proportionately higher due to coal
exposures related to domestic MTM coal transactions. These exposures were driven
by the continued high levels of prices for coal. As of September 30, 2004, the
following table approximates our counterparty credit quality and exposure based
on netting across commodities and instruments:
Number of Net Exposure of
Counterparty Exposure Before Credit Net Counterparties Counterparties
Credit Quality Credit Collateral Collateral Exposure > 10% > 10%
- -------------- ----------------- ---------- -------- -------------- ---------------
(in millions, except number of counterparties)
Investment Grade $924 $145 $779 - $-
Split Rating 30 7 23 3 21
Non-Investment Grade 331 181 150 3 99
No External Ratings:
Internal Investment
Grade 126 - 126 1 16
Internal Non-Investment
Grade 69 4 65 2 43
------- ----- ------- -- -----
Total $1,480 $337 $1,143 9 $179
======= ===== ======= == =====
Generation Plant Hedging Information
- ------------------------------------
This table provides information on operating measures regarding the proportion
of output of our generation facilities (based on economic availability
projections) economically hedged, including both contracts designated as cash
flow hedges under SFAS 133 and contracts not designated as cash flow hedges.
This information is forward-looking and provided on a prospective basis through
December 31, 2006. Please note that this table is a point-in-time estimate,
subject to changes in market conditions and our decisions on how to manage
operations and risk. "Estimated Plant Output Hedged," represents the portion of
megawatthours of future generation/production for which we have sales
commitments or estimated requirement obligations to customers.
Generation Plant Hedging Information
Estimated Next Three Years
As of September 30, 2004
Remainder
2004 2005 2006
---- ---- ----
Estimated Plant Output Hedged 92% 88% 88%
VaR Associated with Risk Management Contracts
- ---------------------------------------------
We use a risk measurement model, which calculates Value at Risk (VaR) to measure
our commodity price risk in the risk management portfolio. The VaR is based on
the variance-covariance method using historical prices to estimate volatilities
and correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at September 30, 2004, a near term typical
change in commodity prices is not expected to have a material effect on our
results of operations, cash flows or financial condition.
The following table shows the end, high, average, and low market risk as
measured by VaR year-to-date:
VaR Model
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
------------------ -------------------
(in millions) (in millions)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$1 $19 $6 $1 $11 $19 $7 $4
The 2004 High VaR was due to the wind-down of the London risk management
activities. These activities were concluded in March 2004. The 2004 High VaR,
excluding London activities, was approximately $8 million.
Our VaR model results are adjusted using standard statistical treatments to
calculate the CCRO VaR reporting metrics listed below.
CCRO VaR Metrics
Average for
Year-to-Date High for Low for
September 30, 2004 2004 Year-to-Date 2004 Year-to-Date 2004
------------------ ------------ ----------------- -----------------
(in millions)
95% Confidence Level, Ten-Day
Holding Period $5 $21 $73 $5
99% Confidence Level, One-Day
Holding Period $2 $9 $30 $2
We utilize a VaR model to measure interest rate market risk exposure. The
interest rate VaR model is based on a Monte Carlo simulation with a 95%
confidence level and a one-year holding period. The volatilities and
correlations were based on three years of daily prices. The risk of potential
loss in fair value attributable to our exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $755 million at
September 30, 2004 and $1.013 billion at December 31, 2003. We would not expect
to liquidate our entire debt portfolio in a one-year holding period. Therefore,
a near term change in interest rates should not materially affect our results of
operations, cash flows or consolidated financial position.
We are exposed to risk from changes in the market prices of coal and natural gas
used to generate electricity where generation is no longer regulated or where
existing fuel clauses are suspended or frozen. The protection afforded by fuel
clause recovery mechanisms has either been eliminated by the implementation of
customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of
Texas (effective January 1, 2002) or frozen by a settlement agreement in West
Virginia. To the extent the fuel supply of the generating units in these states
is not under fixed-price long-term contracts, we are subject to market price
risk. We continue to be protected against market price changes by active fuel
clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of
Texas. Fuel clauses are active again in Michigan and Indiana, effective January
1, 2004 and March 1, 2004, respectively. See Note 3 "Rate Matters" for further
discussion.
We employ risk management contracts including physical forward purchase and sale
contracts, exchange futures and options, over-the-counter options, swaps, and
other derivative contracts to offset price risk where appropriate. We engage in
risk management of electricity, gas and to a lesser degree other commodities,
principally coal and freight. As a result, we are subject to price risk. The
amount of risk taken is controlled by risk management operations and our Chief
Risk Officer and his staff. When risk management activities exceed certain
pre-determined limits, the positions are modified or hedged to reduce the risk
to be within the limits unless specifically approved by the Risk Executive
Committee.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Nine Months Ended September 30, 2004 and 2003
(in millions, except per-share amounts)
(Unaudited)
Three Months Ended Nine Months Ended
---------------------- ---------------------
2004 2003 2004 2003
---- ---- ---- ----
REVENUES
- -----------------------------------------------------
Utility Operations $2,909 $3,099 $7,989 $8,458
Gas Operations 762 707 2,191 2,278
Other 81 135 281 440
------- ------- ------- -------
TOTAL 3,752 3,941 10,461 11,176
------- ------- ------- -------
EXPENSES
- -----------------------------------------------------
Fuel for Electric Generation 781 912 2,209 2,404
Purchased Electricity for Resale 274 207 444 577
Purchased Gas for Resale 725 675 2,011 2,203
Maintenance and Other Operation 843 904 2,679 2,739
Depreciation and Amortization 333 329 972 971
Taxes Other Than Income Taxes 178 179 538 524
------- ------- ------- -------
TOTAL 3,134 3,206 8,853 9,418
------- ------- ------- -------
OPERATING INCOME 618 735 1,608 1,758
------- ------- ------- -------
Other Income (Expense), Net 193 31 286 147
------- ------- ------- -------
Investment Value Losses - 70 2 70
------- ------- ------- -------
INTEREST AND OTHER CHARGES
- -----------------------------------------------------
Interest 193 216 591 605
Preferred Stock Dividend Requirements of Subsidiaries 2 1 5 7
Minority Interest in Finance Subsidiary - - - 17
------- ------- ------- -------
TOTAL 195 217 596 629
------- ------- ------- -------
INCOME BEFORE INCOME TAXES 616 479 1,296 1,206
Income Taxes 204 172 444 429
------- ------- ------- -------
INCOME BEFORE DISCONTINUED OPERATIONS AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGES 412 307 852 777
DISCONTINUED OPERATIONS (Net of Tax) 118 (50) 60 (98)
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (Net of Tax)
- -----------------------------------------------------
Accounting for Risk Management Contracts - - - (49)
Asset Retirement Obligations - - - 242
------- ------- ------- -------
NET INCOME $530 $257 $912 $872
======= ======= ======= =======
WEIGHTED AVERAGE NUMBER OF SHARES
OUTSTANDING 396 395 396 382
======= ======= ======= =======
EARNINGS PER SHARE
- -----------------------------------------------------
Income Before Discontinued Operations and Cumulative
Effect of Accounting Changes $1.04 $0.78 $2.15 $2.03
Discontinued Operations 0.30 (0.13) 0.15 (0.26)
Cumulative Effect of Accounting Changes - - - 0.51
------- ------- ------- -------
TOTAL EARNINGS PER SHARE (BASIC AND DILUTED) $1.34 $0.65 $2.30 $2.28
======= ======= ======= =======
CASH DIVIDENDS PAID PER SHARE $0.35 $0.35 $1.05 $1.30
======= ======= ======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in millions)
CURRENT ASSETS
- ------------------------------------------------------
Cash and Cash Equivalents $1,282 $976
Other Cash Deposits 179 206
Accounts Receivable:
Customers 883 1,155
Accrued Unbilled Revenues 517 596
Miscellaneous 65 83
Allowance for Uncollectible Accounts (132) (124)
-------- --------
Total Receivables 1,333 1,710
-------- --------
Fuel, Materials and Supplies 1,074 991
Risk Management Assets 810 766
Margin Deposits 180 119
Other 125 129
-------- --------
TOTAL 4,983 4,897
-------- --------
PROPERTY, PLANT AND EQUIPMENT
- ------------------------------------------------------
Electric:
Production 15,829 15,112
Transmission 6,248 6,130
Distribution 10,197 9,902
Other (including gas, coal mining and nuclear fuel) 3,488 3,572
Construction Work in Progress 930 1,305
-------- --------
TOTAL 36,692 36,021
Less: Accumulated Depreciation and Amortization 14,398 14,004
-------- --------
TOTAL-NET 22,294 22,017
-------- --------
OTHER NON-CURRENT ASSETS
- ------------------------------------------------------
Regulatory Assets 3,480 3,548
Securitized Transition Assets 656 689
Spent Nuclear Fuel and Decommissioning Trusts 1,029 982
Investments in Power and Distribution Projects 190 212
Goodwill 78 78
Long-term Risk Management Assets 527 494
Other 698 733
-------- --------
TOTAL 6,658 6,736
-------- --------
Assets of Discontinued Operations and Held for Sale 887 3,094
TOTAL ASSETS $34,822 $36,744
======== ========
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in millions)
CURRENT LIABILITIES
- ---------------------------------------------------------------------------------
Accounts Payable $1,033 $1,337
Short-term Debt 214 326
Long-term Debt Due Within One Year* 1,598 1,779
Risk Management Liabilities 903 631
Accrued Taxes 583 620
Accrued Interest 183 207
Customer Deposits 399 379
Other 719 703
-------- --------
TOTAL 5,632 5,982
-------- --------
NON-CURRENT LIABILITIES
- ---------------------------------------------------------------------------------
Long-term Debt* 11,039 12,322
Long-term Risk Management Liabilities 383 335
Deferred Income Taxes 4,520 3,957
Regulatory Liabilities and Deferred Investment Tax Credits 2,290 2,259
Asset Retirement Obligations and Nuclear Decommissioning 696 651
Employee Benefits and Pension Obligations 669 667
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 169 176
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption 72 76
Deferred Credits and Other 622 508
-------- --------
TOTAL 20,460 20,951
-------- --------
Liabilities of Discontinued Operations and Held for Sale 386 1,876
TOTAL LIABILITIES 26,478 28,809
-------- --------
Cumulative Preferred Stocks of Subsidiaries not Subject to Mandatory Redemption 61 61
Commitments and Contingencies
COMMON SHAREHOLDERS' EQUITY
- ---------------------------------------------------------------------------------
Common Stock-Par Value $6.50:
2004 2003
---- ----
Shares Authorized. . . . . . . . . . .600,000,000 600,000,000
Shares Issued. . . . . . . . . . . . .404,695,982 404,016,413
(8,999,992 shares were held in treasury at September 30, 2004 and December 31, 2,630 2,626
2003)
Paid-in Capital 4,197 4,184
Retained Earnings 1,987 1,490
Accumulated Other Comprehensive Income (Loss) (531) (426)
-------- --------
TOTAL 8,283 7,874
-------- --------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $34,822 $36,744
======== ========
* See Accompanying Schedule
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in millions)
OPERATING ACTIVITIES
- --------------------------------------------------------
Net Income $912 $872
Plus: (Income) Loss from Discontinued Operations (60) 98
------- -------
Income from Continuing Operations 852 970
Adjustments for Noncash Items:
Depreciation and Amortization 972 971
Deferred Income Taxes 88 214
Deferred Investment Tax Credits (21) (24)
Cumulative Effect of Accounting Changes - (193)
Investment Value Losses 2 70
Amortization of Deferred Property Taxes 93 89
Amortization of Cook Plant Restart Costs - 30
Mark-to-Market of Risk Management Contracts 89 (124)
Over/Under Fuel Recovery 5 131
Gain on Sales of Assets (156) (40)
Change in Other Non-Current Assets (101) (51)
Change in Other Non-Current Liabilities 130 (32)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net 379 141
Accounts Payable (313) (408)
Fuel, Materials and Supplies (83) (11)
Customer Deposits 19 102
Taxes Accrued 388 (4)
Interest Accrued (25) 4
Other Current Assets (56) 29
Other Current Liabilities 3 (108)
------- -------
Net Cash Flows From Operating Activities 2,265 1,756
------- -------
INVESTING ACTIVITIES
- --------------------------------------------------------
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)
------- -------
FINANCING ACTIVITIES
- --------------------------------------------------------
Issuance of Common Stock 13 1,142
Issuance of Long-term Debt 416 4,065
Change in Short-term Debt, Net (201) (2,523)
Retirement of Long-term Debt (1,898) (1,658)
Retirement of Preferred Stock (4) (2)
Retirement of Minority Interest - (225)
Dividends Paid on Common Stock (415) (479)
------- -------
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 Beginning of Period 976 1,084
------- -------
Cash and Cash Equivalents at End of Period $1,282 $1,620
======= =======
Net Decrease in Cash and Cash Equivalents from Discontinued Operations $(4) $(7)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 13 23
------- -------
Cash and Cash Equivalents from Discontinued Operations - End of Period $9 $16
======= =======
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest, net of capitalized amounts, was $576 million and $542 million in 2004 and 2003, respectively. Cash paid
(received) for income taxes was $(112) million and $156 million in 2004 and 2003, respectively. Noncash acquisitions under
capital leases were $76 million and $9 million in 2004 and 2003, respectively.
In connection with the disposition of AEP Coal in April 2004 the buyer assumed $11 million of non-current liabilities.
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND
COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in millions)
(Unaudited)
Accumulated
Other
Common Stock Paid-in Retained Comprehensive
Shares Amount Capital Earnings Income (Loss) Total
------ ------ ------- -------- ------------- -----
DECEMBER 31, 2002 348 $2,261 $3,413 $1,999 $(609) $7,064
Issuance of Common Stock 56 365 812 1,177
Common Stock Dividends (479) (479)
Common Stock Expense (36) (36)
Other (5) 1 (4)
-------
TOTAL 7,722
-------
COMPREHENSIVE INCOME
- --------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments 25 25
Cash Flow Hedges (177) (177)
Securities Available for Sale 1 1
Minimum Pension Liability 15 15
NET INCOME 872 872
-------
TOTAL COMPREHENSIVE INCOME 736
---- ------- ------- ------- ------ -------
SEPTEMBER 30, 2003 404 $2,626 $4,184 $2,393 $(745) $8,458
==== ======= ======= ======= ====== =======
DECEMBER 31, 2003 404 $2,626 $4,184 $1,490 $(426) $7,874
Issuance of Common Stock 1 4 9 13
Common Stock Dividends (415) (415)
Other 4 4
-------
TOTAL 7,476
-------
COMPREHENSIVE INCOME
- --------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments (113) (113)
Cash Flow Hedges (8) (8)
Minimum Pension Liability 16 16
NET INCOME 912 912
-------
TOTAL COMPREHENSIVE INCOME 807
---- ------- ------- ------- ------ -------
SEPTEMBER 30, 2004 405 $2,630 $4,197 $1,987 $(531) $8,283
==== ======= ======= ======= ====== =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in millions)
First Mortgage Bonds $536 $822
Defeased TCC First Mortgage Bonds (a) 112 118
Installment Purchase Contracts 1,935 2,026
Notes Payable 1,049 1,518
Senior Unsecured Notes 7,640 7,997
Securitization Bonds 698 746
Notes Payable to Trust 113 331
Equity Unit Senior Notes 345 345
Long-term DOE Obligation (b) 228 226
Other Long-term Debt 22 21
Equity Unit Contract Adjustment Payments 12 19
Unamortized Discount (net) (53) (68)
-------- --------
TOTAL LONG-TERM DEBT OUTSTANDING 12,637 14,101
Less Portion Due Within One Year 1,598 1,779
-------- -------
TOTAL LONG-TERM PORTION $11,039 $12,322
======== =======
(a) On May 7, 2004, we deposited cash and treasury securities of $125
million with a trustee to defease all of TCC's outstanding First Mortgage
Bonds. Trust fund assets related to this obligation of $100 million are
included in Other Cash Deposits and $22 million are included in Other
Non-current Assets in the Consolidated Balance Sheets at September 30, 2004.
Trust fund assets are restricted for exclusive use in funding the interest
and principal due on the First Mortgage Bonds.
(b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear
licensee) has an obligation with the United States Department of Energy for
spent nuclear fuel disposal. The obligation includes a one-time fee for
nuclear fuel consumed prior to April 7, 1983. I&M is the only AEP subsidiary
that generated electric power with nuclear fuel prior to that date. Trust
fund assets of $261 million and $262 million related to this obligation are
included in Spent Nuclear Fuel and Decommissioning Trusts in the
Consolidated Balance Sheets at September 30, 2004 and December 31, 2003,
respectively.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Matters
2. New Accounting Pronouncements
3. Rate Matters
4. Customer Choice and Industry Restructuring
5. Commitments and Contingencies
6. Guarantees
7. Dispositions, Discontinued Operations and Assets Held for Sale
8. Benefit Plans
9. Business Segments
10. Financing Activities
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING MATTERS
------------------------------
General
- -------
The accompanying unaudited interim financial statements should be read in
conjunction with the 2003 Annual Report as incorporated in and filed with our
2003 Form 10-K.
In the opinion of management, the unaudited interim financial statements reflect
all normal and recurring accruals and adjustments which are necessary for a fair
presentation of our results of operations for interim periods.
Other Income (Expense), Net
- ---------------------------
The following table provides the components of Other Income (Expense), Net as
presented on our Consolidated Statements of Operations:
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Other Income:
- -------------
Interest and Dividend Income $6 $8 $17 $21
Equity Earnings 5 4 15 6
Nonoperating Revenue 27 34 84 100
Gain on Sale of IPPs (a) 105 - 105 -
Gain on Sale of South Coast (a) 48 - 48 -
Gain on Sale of REPs (Mutual Energy Companies) - - - 39
Other 39 34 124 134
----- ---- ----- -----
Total Other Income 230 80 393 300
----- ---- ----- -----
Other Expense:
- --------------
Nonoperating Expenses 21 28 67 88
Other 16 21 40 65
----- ---- ----- -----
Total Other Expense 37 49 107 153
----- ---- ----- -----
Total Other Income (Expense), Net $193 $31 $286 $147
===== ==== ===== =====
(a) See Note 7 "Dispositions, Discontinued Operations and Assets Held for Sale."
Components of Accumulated Other Comprehensive Income (Loss)
- -----------------------------------------------------------
The following table provides the components that constitute the balance sheet
amount in Accumulated Other Comprehensive Income (Loss):
September 30, December 31,
Components 2004 2003
- ---------- ------------- ------------
(in millions)
Foreign Currency Translation Adjustments $(3) $110
Unrealized Losses on Securities Available for Sale (1) (1)
Unrealized Losses on Cash Flow Hedges (102) (94)
Minimum Pension Liability (425) (441)
------ ------
Total $(531) $(426)
====== ======
At September 30, 2004, we expect to reclassify approximately $78 million of net
losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to
Net Income during the next twelve months at the time the hedged transactions
affect net income. Seventeen months is the maximum period over which an exposure
to a variability in future commodity related cash flows is hedged with SFAS 133
designated contracts. Approximately $1 million of the fair value of cash flow
hedges at September 30, 2004 are hedging interest rate variability on debt past
two years. The actual amounts that we reclassify from Accumulated Other
Comprehensive Income (Loss) to Net Income can differ due to market price
changes.
In addition, during the first quarter 2004, we reclassified $23 million from
Accumulated Other Comprehensive Income (Loss) related to minimum pension
liability to regulatory assets ($35 million) and deferred income taxes ($12
million) as a result of authoritative letters issued by the FERC and the
Arkansas and Louisiana commissions.
Accounting for Asset Retirement Obligations
- -------------------------------------------
The following is a reconciliation of the beginning and ending aggregate carrying
amount of asset retirement obligations:
U.K. Plants,
Wind Mills
Nuclear Ash and Mining
Decommissioning Ponds Operations Total
--------------- ----- ------------ -----
(in millions)
Asset Retirement Obligation
Liability at January 1, 2004
Including Held for Sale $770.9 $75.4 $53.1 $899.4
Accretion Expense 41.9 4.5 2.4 48.8
Foreign Currency
Translation - - 0.6 0.6
Liabilities Incurred - - 17.7 17.7
Liabilities Settled - (0.4) (56.9) (57.3)
Revisions in Cash Flow Estimates - - 15.0 15.0
------- ------ ------ -------
Asset Retirement Obligation
Liability at September 30, 2004
including Held for Sale 812.8 79.5 31.9 924.2
Less Asset Retirement Obligation
Liability Held for Sale:
South Texas Project (a) (231.2) - - (231.2)
------- ------ ------ -------
Asset Retirement Obligation
Liability at September 30, 2004 $581.6 $79.5 $31.9 $693.0
======= ====== ====== =======
(a) We have signed an agreement to sell TCC's share of South Texas Project (see Note 7 for additional information).
Accretion expense is included in Maintenance and Other Operation expense in our
accompanying Consolidated Statements of Operations.
At September 30, 2004 and December 31, 2003, the fair value of assets that are
legally restricted for purposes of settling the nuclear decommissioning
liabilities totaled $902 million and $845 million, respectively, of which $768
million and $720 million relating to the Cook Plant was recorded in Spent
Nuclear Fuel and Decommissioning Trusts in our Consolidated Balance Sheets. The
fair value of assets that are legally restricted for purposes of settling the
nuclear decommissioning liabilities for the South Texas Project totaling $134
million and $125 million as of September 30, 2004 and December 31, 2003,
respectively, was classified as Assets of Discontinued Operations and Held for
Sale in our Consolidated Balance Sheets.
Reclassifications
- -----------------
Certain prior period financial statement items have been reclassified to conform
to current period presentation. Such reclassifications had no impact on
previously reported Net Income.
2. NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------
FASB Interpretation Number (FIN) 46 (revised December 2003)"Consolidation of
Variable Interest Entities" FIN 46R
- ----------------------------------------------------------------------------
We implemented FIN 46R, "Consolidation of Variable Interest Entities," effective
March 31, 2004 with no material impact to our financial statements. FIN 46R is a
revision to FIN 46 which interprets the application of Accounting Research
Bulletin No. 51, "Consolidated Financial Statements," to certain entities in
which equity investors do not have the characteristics of a controlling
financial interest or do not have sufficient equity at risk for the entity to
finance its activities without additional subordinated financial support from
other parties.
FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug Improvement and Modernization Act
of 2003
- ------------------------------------------------------------------------------
We implemented FASB Staff Position (FSP) FAS 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003," effective April 1, 2004, retroactive to January 1,
2004. The new disclosure standard provides authoritative guidance on the
accounting for any effects of the Medicare prescription drug subsidy under the
Act. It replaces the earlier FSP FAS 106-1, under which we previously elected to
defer accounting for any effects of the Act until the FASB issued authoritative
guidance on the accounting for the Medicare subsidy.
Under FSP FAS 106-2, the current portion of the Medicare subsidy for employers
who qualify for the tax-free subsidy is a reduction of ongoing FAS 106 cost,
while the retroactive portion is an actuarial gain to be amortized over the
average remaining service period of active employees, to the extent that the
gain exceeds FAS 106's 10 percent corridor. The Medicare subsidy reduced our FAS
106 accumulated postretirement benefit obligation (APBO) related to benefits
attributed to past service by $202 million. The tax-free subsidy reduced the
2004 year-to-date net periodic postretirement benefit cost, after adjustment to
capitalization of employee benefits costs as a cost of construction projects, by
a total of $20 million.
Future Accounting Changes
- -------------------------
The FASB's standard-setting process is ongoing and until new standards have been
finalized and issued by FASB, we cannot determine the impact on the reporting of
our operations that may result from any such future changes. The FASB is
currently working on several projects including discontinued operations,
business combinations, liabilities and equity, revenue recognition, accounting
for share-based compensation, pension plans, asset retirement obligations,
earnings per share calculations, fair value measurements, accounting changes and
related tax impacts. We also expect to see more FASB projects as a result of
their desire to converge International Accounting Standards with those generally
accepted in the United States of America. The ultimate pronouncements resulting
from these and future projects could have an impact on our future results of
operations and financial position.
3. RATE MATTERS
------------
As discussed in our 2003 Annual Report, our subsidiaries are involved in rate
and regulatory proceedings at the FERC and at several state commissions. The
Rate Matters note within our 2003 Annual Report should be read in conjunction
with this report in order to gain a complete understanding of material rate
matters still pending, without significant changes since year-end. The following
sections discuss current activities.
TNC Fuel Reconciliation
- -----------------------
In 2002, TNC filed with the PUCT to reconcile fuel costs, requesting to defer
any unrecovered portion applicable to retail sales within its ERCOT service area
for inclusion in the True-up Proceeding. This reconciliation for the period from
July 2000 through December 2001 will be the final fuel reconciliation for TNC's
ERCOT service territory.
In March 2003, the ALJ in this proceeding filed a Proposal for Decision (PFD)
with a recommendation that TNC's under-recovered retail fuel balance be reduced.
In March 2003, TNC established a provision for probable disallowance of $13
million based on the recommendations in the PFD. In May 2003, the PUCT reversed
the ALJ on certain matters and remanded TNC's final fuel reconciliation to the
ALJ to consider two issues: (1) the sharing of off-system sales margins from
AEP's trading activities with customers for five years per the PUCT's
interpretation of the Texas AEP/CSW merger settlement and (2) the inclusion of
January 2002 fuel factor revenues and associated costs in the determination of
the under-recovery. The PUCT proposed that the sharing of off-system sales
margins for periods beyond the termination of the fuel factor should be
recognized in the final fuel reconciliation proceeding. This would result in the
sharing of margins for an additional three and one-half years after the end of
the Texas ERCOT fuel factor. While management believes that the Texas merger
settlement only provided for sharing of margins during the period fuel and
generation costs were regulated by the PUCT, an additional provision of $10
million was recorded in December 2003.
In December 2003, the ALJ issued a PFD in the remand phase of the TNC fuel
reconciliation recommending additional disallowances for the two remand issues.
TNC filed responses to the PFD, and the PUCT announced a final ruling in the
fuel reconciliation proceeding in January 2004 accepting the PFD. TNC received a
written order in March 2004 and increased its provision by $1.5 million. In
March 2004, various parties, including TNC, requested a rehearing of the PUCT's
ruling. In May 2004, the PUCT reversed its position on the inclusion of MTM
amounts in the allocation of system sales margins and remanded the case to the
ALJ. As a result, TNC recorded an additional provision of $12 million in the
second quarter of 2004 resulting in a provision for an over-recovery balance of
approximately $7 million.
On July 2, 2004, the parties to the MTM remand proceeding filed a "Stipulation
of Fact" in which all parties agreed to the quantification of the remanded
issue. With the amounts included in the "Stipulation of Fact," the over-recovery
balance would be $4 million. On October 13, 2004 the PUCT approved an order
which included the amounts contained in the "Stipulation of Fact." The PUCT
issued an order in the fuel reconciliation which reflected the "Stipulation of
Fact" in October 2004. TNC will seek rehearing of the PUCT's order regarding
issues other than the issue covered by the stipulation. TNC may appeal to the
Texas District Court the PUCT's decision once all motions for rehearing have
been adjudicated. Management expects to adjust its provision to an over-recovery
balance of $4 million when it receives a final order in the fourth quarter 2004.
Although management believes it has adequately provided for probable
disallowances, a final order from the PUCT disallowing amounts in excess of the
established provision could have a material adverse impact on future results of
operations and cash flows.
In February 2002, TNC received a final order from the PUCT in a previous fuel
reconciliation covering the period July 1997 through June 2000 and reflected the
order in its financial statements. This final order was appealed to the Travis
County District Court. In May 2003, the District Court upheld the PUCT's final
order. That order was appealed by certain cities (the Cities) to the Third Court
of Appeals. The Third Court of Appeals issued a ruling on September 23, 2004
upholding the District Court and the PUCT's final order. It is unknown at this
time if the Cities will appeal to the Texas Supreme Court or if the court will
hear the issue if they do.
TCC Fuel Reconciliation
- -----------------------
In 2002, TCC filed its final fuel reconciliation with the PUCT to reconcile fuel
costs to be included in its deferred over-recovery balance in the True-up
Proceeding. This reconciliation covers the period from July 1998 through
December 2001.
Based on the PUCT ruling in the TNC proceeding related to similar issues, TCC
established a provision for probable adverse rulings of $81 million during 2003.
On February 3, 2004, the ALJ issued a PFD in the TCC case recommending that the
PUCT disallow $140 million in eligible fuel costs including some new items not
considered in the TNC case, and other items considered but not disallowed in the
TNC ruling. Based on an analysis of the ALJ's recommendations and the initial
final order in the TNC fuel reconciliation, TCC established an additional
provision of $13 million during the first quarter of 2004. In May 2004, the PUCT
accepted most of the ALJ's recommendations in the TCC case, however, the PUCT
rejected the ALJ's recommendation to impute capacity to certain energy-only
purchased power contracts and remanded the issue to the ALJ to determine if any
energy-only purchased power contracts during the reconciliation period include a
capacity component that is not recoverable in fuel revenues. In testimony filed
in the remand proceeding, TCC has asserted that its energy-only purchased power
contracts do not include any capacity component. Intervenors, including the
Office of Public Utility Counsel, have filed testimony recommending that $15
million to $30 million of TCC's purchased power costs reflect capacity costs
which are not recoverable in the fuel reconciliations. Hearings were held in
October 2004 on this remand issue. As a result of the PUCT's acceptance of most
of the ALJ's recommendations in TCC's case and the PUCT's remand decision in the
TNC case regarding the inclusion of MTM amounts in the allocation of AEP's net
system sales margins, TCC increased its provision by $47 million in the second
quarter of 2004. The over-recovery balance and the provisions for probable
disallowances totaled $210 million including interest at September 30, 2004.
At this time, management is unable to predict the outcome of this proceeding.
Management believes it has provided for all probable to-date disallowances
pending receipt of a final order. A final order has not yet been issued in TCC's
final fuel reconciliation. We will continue to challenge adverse decisions
vigorously, including appeals if necessary. An order from the PUCT, disallowing
amounts in excess of the established provision, could have a material adverse
effect on future results of operations and cash flows. Additional information
regarding the True-up Proceeding for TCC can be found in Note 4 "Customer
Choice and Industry Restructuring."
SWEPCo Texas Fuel Reconciliation
- --------------------------------
In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in the SPP.
This reconciliation covers the period from January 2000 through December 2002.
During the reconciliation period, SWEPCo incurred $435 million of Texas retail
eligible fuel expense. In November 2003, intervenors and the PUCT Staff
recommended fuel cost disallowances of more than $30 million. In December 2003,
SWEPCo agreed to a settlement in principle with all parties in the fuel
reconciliation. The settlement provides for a disallowance in fuel costs of $8
million which was recorded in December 2003. In April 2004 the PUCT approved the
settlement.
Virginia Fuel Factor Filing
- ---------------------------
On October 29, 2004 APCo filed with the Virginia SCC to increase its fuel factor
effective January 1, 2005. The requested factor is estimated to increase
revenues by approximately $19 million on an annual basis. This increase reflects
a continuing rise in the projected cost of coal in 2005. This fuel factor
adjustment will increase cash flows without impacting results of operations as
any over-recovery or under-recovery of fuel cost would be deferred as a
regulatory liability or a regulatory asset.
TCC Rate Case
- -------------
On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates should not be
reduced. Other municipalities served by TCC passed similar rate review
resolutions. In Texas, municipalities have original jurisdiction over rates of
electric utilities within their municipal limits. Under Texas law, TCC must
provide support for its rates to the municipalities. TCC filed the requested
support for its rates based on a test year ending June 30, 2003 with all of its
municipalities and the PUCT on November 3, 2003. TCC's proposal would decrease
its wholesale transmission rates by $2 million or 2.5% and increase its retail
energy delivery rates by $69 million or 19.2%.
In February 2004, eight intervening parties and the PUCT Staff filed testimony
recommending reductions to TCC's requested $67 million rate increase. The
recommendations ranged from a decrease in existing rates of approximately $100
million to an increase in TCC's current rates of approximately $27 million.
Hearings were held in March 2004. In May 2004, TCC agreed to a non-unanimous
settlement on cost of capital including capital structure and return on equity
with all but two parties in the proceeding. TCC agreed that the return on equity
should be established at 10.125% based upon a capital structure with 40% equity
resulting in a weighted cost of capital of 7.475%. The settlement and other
agreed adjustments reduced TCC's rate request from $67 million to $41 million.
The ALJs that heard the case issued their recommendations on July 2, 2004,
including a recommendation to approve the cost of capital settlement. The ALJs
recommended that an issue related to the allocation of consolidated tax savings
to the transmission and distribution utility be remanded for additional
evidence. On July 15, 2004, the PUCT remanded this issue to the ALJs. On August
19, 2004, in a separate ruling the PUCT remanded six other issues to the ALJs
requesting revisions to clarify and further support the recommendations in the
PFD. In addition, the PUCT ordered TCC to calculate its revenue requirements
based upon the recommendations of the ALJs. On July 21, 2004, TCC filed its
revenue requirements based upon the recommendations of the ALJs. According to
TCC's calculations, the ALJs' recommendations reduce TCC's existing rates by a
range of somewhere between $33 million and $43 million depending on the final
resolution of the amount of consolidated tax savings. Hearings were held on the
consolidated tax savings remand issue in September. The PUCT is expected to
issue its decision by the end of 2004. Management is unable to predict the
ultimate effect of this proceeding on TCC's rates, revenues, results of
operations, cash flows and financial condition.
On September 2, 2004, a group of intervenors, with subsequent support of the
PUCT Staff, filed a request that a $30 million temporary, or interim, rate
reduction be ordered subject to refund or surcharge. On September 24, 2004 the
PUCT issued an order denying the motion for reduced temporary rates.
Louisiana Compliance Filing
- ---------------------------
In October 2002, SWEPCo filed with the Louisiana Public Service Commission
(LPSC) detailed financial information typically utilized in a revenue
requirement filing, including a jurisdictional cost of service. This filing was
required by the LPSC as a result of its order approving the merger between AEP
and CSW. The LPSC's merger order also provides that SWEPCo's base rates are
capped at the present level through mid-2005. In April 2004, SWEPCo filed
updated financial information with a test year ending December 31, 2003 as
required by the LPSC. Both filings indicated that SWEPCo's current rates should
not be reduced. Subsequently, direct testimony was filed on behalf of the LPSC
recommending a $15.4 million reduction in SWEPCo's Louisiana jurisdictional base
rates. SWEPCo's rebuttal testimony is due December 15, 2004. At this time,
management is unable to predict the outcome of this proceeding. If a rate
reduction is ordered in the future, it would adversely impact results of
operations and cash flows.
Louisiana Fuel Audit
- --------------------
The LPSC is performing an audit of SWEPCo's historical fuel costs. In addition,
five SWEPCo customers filed a suit in the Caddo Parish District Court in January
2003 and filed a complaint with the LPSC. The customers claim that SWEPCo has
overcharged them for fuel costs since 1975. The LPSC consolidated the customer
complaint and audit. A status conference is scheduled for December 16, 2004 to
schedule a hearing date. Although management believes that SWEPCo's fuel costs
were proper and fuel costs incurred prior to 1999 were approved by the LPSC, we
are unable to predict the outcome of these proceedings. If the actions of the
LPSC or the Court result in a material disallowance of SWEPCo's fuel recoveries,
it would have an adverse impact on results of operations and cash flows. The
LPSC Staff consultant made recommendations to reduce recoverable fuel expense
from SWEPCo's Louisiana retail customers. The consultant recommended that SWEPCo
be required to refund $3.9 million (through December 2002) stating the amount
should be recovered through base rates versus the fuel factor. An additional
amount of $1.4 million for the period of January 2003 through September 2004
would also be required to be refunded. In addition, the LPSC Staff contends that
SWEPCo's Pirkey Power Plant experienced poor performance during the years 1999,
2001 and 2002 and that the incremental cost of replacement power should be
refunded. The consultant did not provide an amount associated with this
recommendation, but management believes that the amount could be material. If
the LPSC adopts any of the consultant's recommendations, it would adversely
impact results of operations and cash flows.
PSO Fuel and Purchased Power
- ----------------------------
In 2002, PSO experienced 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. In July 2003, PSO filed with
the OCC seeking to recover these reallocated costs over a period of 18 months.
In August 2003, the OCC Staff filed testimony recommending PSO be granted
recovery of $42.4 million of the reallocation over three years. In September
2003, the OCC expanded the case to include a full review of PSO's 2001 fuel and
purchased power practices. PSO filed testimony in February 2004. An intervenor
and the OCC Staff filed testimony in April 2004. The intervenor suggested that
$8.8 million related to the 2002 reallocation not be recovered from customers.
The Attorney General of Oklahoma also filed a statement of position, indicating
allocated off-system sales margins between and among AEP operating companies
were inconsistent with the FERC-approved Operating Agreement and System
Integration Agreement and if corrected could more than offset the $44 million
2002 reallocation under-recovery. The intervenor and the OCC Staff also believed
off-system sales margins were allocated incorrectly and that a reallocation by
the intervenors of such margins would reduce PSO's recoverable fuel by an
additional $6.8 million for 2000 and $10.7 million for 2001, while under the OCC
Staff method, the reduction for 2001 would be $8.8 million. The intervenor and
the OCC Staff also recommend recalculation of fuel for years subsequent to 2001
using the same revised methods. 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.
PSO Rate Review
- ---------------
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. Hearings are scheduled to begin in February 2005 to address cost of
service, fuel procurement and resource planning issues.
On August 12, 2004, PSO filed a motion to amend the schedule to consider new
service quality and reliability requirements which took effect on July 1, 2004.
On August 30, 2004, the OCC approved a revised schedule. On October 4, 2004, PSO
filed supplemental information requesting consideration of approximately $55
million of additional annual operations and maintenance expenses and annual
capital costs to enhance system reliability. On November 4, 2004, PSO filed a
plan with the OCC seeking interim rate relief to fund a portion of the costs
to meet the new state service quality and reliability requirements pending
the outcome of the current case. In the filing, PSO seeks interim approval to
collect incremental distribution tree trimming costs of approximately $29
million from its customers. The OCC Staff and intervenors are scheduled to
file testimony regarding their recommendations on revenue requirement, fuel
procurement, resource planning and vegetation management in December 2004.
Rebuttal testimony is to be filed in January 2005 with hearings beginning in
February 2005. 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.
RTO Formation/Integration
- -------------------------
Based on FERC approvals in response to non-affiliated companies' requests to
defer RTO formation costs, the AEP East companies deferred costs incurred under
FERC orders to originally form a new RTO (the Alliance RTO) or subsequently to
join an existing RTO (PJM). In July 2003, the FERC issued an order approving our
continued deferral of both Alliance RTO formation costs and PJM integration
costs including the deferral of a carrying charge thereon. The AEP East
companies have deferred approximately $35 million of RTO formation and
integration costs and related carrying charges through September 30, 2004. As a
result of the subsequent delay in the integration of AEP's East transmission
system into PJM, the FERC declined to rule, in its July 2003 order, on our
request to transfer the deferrals to regulatory assets, and to maintain such
deferrals until such time as the costs can be recovered from all users of AEP's
East transmission system.
In its July 2003 order, the FERC indicated that it would review the deferred
costs at the time they are transferred to a regulatory asset account and
scheduled for amortization and recovery in the open access transmission tariff
(OATT) to be charged by PJM. Management believes that the FERC will grant
permission for prudently incurred deferred RTO formation/integration costs to be
amortized and included in the OATT. Whether the amortized costs will be fully
recoverable depends upon the state regulatory commissions' treatment of the AEP
East companies' portion of the OATT as these companies file rate cases.
Presently, retail base rates are frozen or capped and cannot be increased for
retail customers of CSPCo and OPCo until 2006 and I&M until 2005.
In August 2004, we filed an application with the FERC dividing the RTO
formation/integration costs between PJM-billed integration costs including
related carrying charges, and all other RTO formation/integration costs. We
intend to file with the FERC to request that deferred PJM-billed integration
costs be recovered. The AEP East companies will be responsible for paying the
amount allocated by the FERC to the AEP zone since it will be attributable to
their internal load. In our August 2004 application, we requested permission
to amortize approximately one-half of the deferred costs within the AEP zone
over fifteen years beginning on January 1, 2005. We also requested to
begin amortizing the deferred PJM-billed integration costs on January 1, 2005,
but we did not propose an amortization period in the application.
In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO prior to July 1, 2004 and thereafter only
with the approval of the Virginia SCC, but required APCo join an RTO by January
1, 2005. In January 2004, APCo filed with the Virginia SCC a cost/benefit study
covering the time period through 2014 as required by the Virginia SCC. The study
results show a net benefit of approximately $98 million for APCo over the
11-year study period from AEP's participation in PJM. In August 2004, the
Virginia SCC approved a stipulation that permits APCo to join PJM.
In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack
of evidence that it would benefit Kentucky retail customers. In August 2003,
KPCo sought and was granted a rehearing to submit additional evidence. In
December 2003, AEP filed with the KPSC a cost/benefit study showing a net
benefit of approximately $13 million for KPCo over the five-year study period
from AEP's participation in PJM. In May 2004, the KPSC approved a stipulation
that permits KPCo to join PJM and the FERC approved the stipulation in June
2004.
In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to certain
conditions included in the order. The IURC's order stated that AEP shall request
and the IURC shall complete a review of Alliance formation costs before any
future recovery. I&M noted in its response to the IURC that it deferred such
costs under the July 2003 FERC order.
In November 2003, the FERC issued an order preliminarily finding that AEP must
fulfill its CSW merger condition to join an RTO by integrating into PJM
(transmission and markets) by October 1, 2004. The order was based on PURPA
205(a), which allows the FERC to exempt electric utilities from state law or
regulation in certain circumstances. The FERC set several issues for public
hearing before an ALJ. Those issues include whether the laws, rules, or
regulations of Virginia and Kentucky are preventing AEP from joining an RTO and
whether the exceptions under PURPA 205(a) apply. The FERC ALJ affirmed the
FERC's preliminary findings in March 2004. The FERC issued an order related to
this matter in June 2004 affirming its preliminary findings. In September 2004,
Virginia filed an offer of settlement with the FERC in which they agreed to
cease all attempts to obtain judicial relief from the June 2004 order on the
condition that the FERC vacate the order. The FERC has not ruled on Virginia's
settlement offer.
The AEP East companies integrated into PJM on October 1, 2004. The AEP East
state regulatory Commissions have approved our integration with PJM and FERC has
ordered us to defer our RTO formation/integration costs. Such costs will be
recovered on an amortization basis through an OATT tariff charged to users of
the system. The AEP East companies will also be charged by PJM for use of the
system. AEP plans to seek recovery for the portion of the deferred RTO costs
that are billed to the AEP East companies by PJM in future rate proceedings. The
AEP East companies will expense their portion of the costs billed by PJM.
Management is unable to predict whether the FERC will grant a long enough
amortization period to allow for the opportunity for recovery of the non-PJM
billed deferred RTO formation/integration costs in the AEP East state retail
jurisdictions, and whether the state regulatory Commissions will ultimately
permit recovery of such costs billed to the AEP East companies by PJM. If the
FERC ultimately decides not to approve an amortization period that would provide
us with the opportunity to include such costs in future retail rate filings or
the FERC or the state commissions deny recovery of our share of these costs,
future results of operations and cash flows could be adversely affected.
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 expanded PJM 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. The order provided that affected
transmission owners could file to offset the elimination of these revenues by
increasing rates or utilizing a transitional rate mechanism to recover lost
revenues that result from the elimination of the T&O rates. The FERC also found
that the T&O rates of certain other companies that were then planning to join
either PJM or Midwest Independent System Operator (MISO) ("Former Alliance RTO
Participants"), including AEP, may be unjust, unreasonable, and unduly
discriminatory or preferential for energy delivered in the Combined Footprint.
The FERC also initiated an investigation and hearing in regard to these rates.
In November 2003, the FERC issued an order finding that the T&O rates of the
Former Alliance RTO Participants should also be eliminated for transactions
within the Combined Footprint. The order directed the RTOs and Former Alliance
RTO Participants, including AEP, to file compliance rates to eliminate T&O rates
prospectively within the Combined Footprint and simultaneously implement a
load-based transitional rate mechanism called the seams elimination cost
allocation (SECA), to mitigate the lost T&O revenues for a two-year transition
period beginning April 1, 2004. The FERC was expected to implement a new rate
design after the two-year period. As required by the FERC, AEP filed compliance
tariff changes in January 2004 to eliminate the T&O charges within the Combined
Footprint. Various parties raised issues with the SECA rate orders and the FERC
implemented settlement procedures before an ALJ.
In April 2004, the FERC approved a settlement that delayed elimination of T&O
rates until December 1, 2004 and provided principles and procedures for
development of a new rate design for the Combined Footprint, to be effective on
December 1, 2004. The settlement also provides that if the process did not
result in the implementation of a new rate design on December 1, then the SECA
rates will be implemented and will remain in effect until a new rate is
implemented by the FERC. If implemented, the SECA rate would not be effective
beyond March 31, 2006.
On September 16, 2004 the FERC Chief ALJ, acting as Settlement Judge, reported
to the FERC that attempts to settle the issues had failed, and at least two
competing long-term rate design proposals for the Combined Footprint were filed
on October 1, 2004. 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.
Indiana Fuel Order
- ------------------
On August 27, 2003, the IURC ordered that certain parties must negotiate the
appropriate action on I&M's fuel cost recovery beginning March 1, 2004,
following the February 2004 expiration of a fixed fuel adjustment charge (fixed
pursuant to a prior settlement of the Cook Nuclear Plant outage issues). The
fixed fuel adjustment charge capped fuel recoveries. In an agreement in
connection with AEP's planned corporate separation, I&M agreed, contingent on
AEP implementing the corporate separation, to a fixed fuel adjustment charge
beginning March 2004 and continuing through December 2007. Although we have not
corporately separated, certain parties believe the fixed fuel adjustment charge
should continue beyond February 2004. Negotiations with the parties to resolve
this issue are ongoing. The IURC ordered that the fixed fuel adjustment charge
remain in place, on an interim basis, in March and April 2004.
In April 2004, the IURC issued an order that extended the interim fuel factor
for May through September 2004, subject to true-up to actual fuel costs
following the resolution of the issue regarding the corporate separation
agreement. The IURC also issued an order that reopened the corporate separation
docket to investigate issues related to the corporate separation agreement. In
July 2004, we filed for approval of a fuel factor for the period October 2004
through March 2005. On September 22, 2004, the IURC issued an order extending
the interim fuel factor for October 2004 through March 2005, subject to true-up
upon resolution of the corporation separation issues. At September 30, 2004, I&M
has over-recovered its fuel costs and has recorded a regulatory liability to
refund such over-recovery. However, if I&M's position should shift to a net
under-recovery, the fixed fuel adjustment factor, capping the fuel revenues,
could adversely affect results of operations and cash flows if recovery is
denied by the IURC.
Michigan 2004 Fuel Recovery Plan
- --------------------------------
A 1999 Michigan Public Service Commission (MPSC) order approved a Settlement
Agreement regarding the extended outage of the Cook Plant and fixed I&M's Power
Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers rate
areas through December 2003. As required, I&M filed its 2004 PSCR Plan with the
MPSC on September 30, 2003 seeking new fuel and power supply recovery factors to
be effective in 2004. A public hearing was held on March 10, 2004. On June 4,
2004, the ALJ recommended that SO2 and NOx net credits be excluded from the fuel
recovery mechanism. I&M filed its exceptions in June 2004. A MPSC order is
expected during the fourth quarter of 2004. As allowed by Michigan law, the
proposed factors were effective on January 1, 2004, subject to review by the
MPSC and possible adjustment. When SO2 and NOx are a net cost exclusion from the
fuel cost recovery mechanism, it will adversely affect future results of
operations and cash flows. On September 30, 2004, I&M filed its 2005 PSCR Plan.
4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
------------------------------------------
As discussed in our 2003 Annual Report, we are affected by customer choice
initiatives and industry restructuring. The Customer Choice and Industry
Restructuring note in our 2003 Annual Report should be read in conjunction with
this report in order to gain a complete understanding of material customer
choice and industry restructuring matters without significant changes since
year-end. The following paragraphs discuss significant current events related to
customer choice and industry restructuring.
OHIO RESTRUCTURING
- ------------------
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. The MDP began on January 1, 2001 and is scheduled to
terminate no later than December 31, 2005. The Public Utilities Commission of
Ohio (PUCO) may terminate the MDP for one or more customer classes before that
date if it determines either that effective competition exists in the incumbent
utility's certified territory or that there is a twenty percent switching rate
of the incumbent utility's load by customer class. Following the MDP, retail
customers will receive cost-based regulated distribution and transmission
service from the incumbent utility whose distribution rates will be approved by
the PUCO and whose transmission rates will be approved by the FERC. Retail
customers will continue to have the right to choose their electric power
suppliers or receive Default Service, which must be offered by the incumbent
utility at market rates.
On December 17, 2003, the PUCO adopted a set of rules concerning the method by
which it will determine market rates for Default Service following the MDP. The
rules provide for a Market Based Standard Service Offer (MBSSO) which would be a
variable rate based on a transparent forward market, daily market, and/or hourly
market prices. The rules also require a fixed-rate Competitive Bidding Process
(CBP) for residential and small nonresidential customers and permits a
fixed-rate CBP for large general service customers and other customer classes.
Customers who do not switch to a competitive generation provider can choose
between the MBSSO and the CBP. Customers who make no choice will be served
pursuant to the CBP. The rules also required that electric distribution
utilities file an application for MBSSO and CBP by July 1, 2004. CSPCo and OPCo
were recently granted a waiver from making the required MBSSO/CBP filing,
pending the outcome of a rate stabilization plan they filed with the PUCO in
February 2004.
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 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. For
residential customers, however, if the temporary 5% generation rate discount
provided by the Ohio Act were eliminated prior to December 31, 2005 as permitted
by the Ohio Act, the fixed increases would be adjusted downward to reflect the
effect of such elimination. Additionally, the plan includes the opportunity to
annually request an additional increase averaging 4% per year for both companies
in the event costs run beyond the level currently anticipated. The plans would
maintain distribution rates through the end of 2008 for CSPCo and OPCo at the
level effective on December 31, 2005. Such rates could be adjusted for specified
reasons. Transmission charges could also be adjusted to reflect applicable
charges approved by the FERC related to open access transmission, net
congestion, and ancillary services. The plans also provide for continued
amortization and recovery of stranded transition generation-related regulatory
assets and for the deferral as regulatory assets in 2004 and 2005 of RTO costs
and carrying charges on governmentally mandated, mainly environmental, capital
expenditures. Hearings were held in June 2004 on the Companies' proposed rate
stabilization plans. Briefs were submitted in July. The filings are pending
before the PUCO.
The PUCO, in a recent order involving a non-affiliated company's rate
stabilization plan, noted its reluctance to authorize automatic increases in any
portion of rates and required a PUCO determination in the future prior to
adjusting a rate component, instead of the automatic increases to the rate
component which had been proposed. It also held that deferral during the MDP of
certain expenses at issue in the case, for recovery after the MDP, would violate
the rate cap under the Ohio Act. The PUCO has been asked in that case to
reconsider these holdings and that request currently is pending. OPCo's and
CSPCo's rate plans and the record in its cases are distinct from the rate plan
and record considered by the PUCO in its recent order. In that regard, 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 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.
As provided in stipulation agreements approved by the PUCO in 2000, we are
deferring customer choice implementation costs and related carrying costs that
are in excess of $40 million. The agreements provide for the deferral of these
costs as a regulatory asset until the next distribution base rate cases. Through
September 30, 2004, we incurred $75 million of such costs, and accordingly, we
deferred $35 million for probable future recovery in distribution rates.
Recovery of these regulatory assets will be subject to PUCO review in future
Ohio filings for new distribution rates. If the rate stabilization plan is
approved as filed, it would defer recovery of these amounts until the next
distribution rate filing. Management believes that its deferred customer choice
implementation costs were prudently incurred and should be recoverable in future
distribution rates. If the PUCO determines that any of the deferred costs are
unrecoverable, it would have an adverse impact on future results of operations
and cash flows.
TEXAS RESTRUCTURING
- -------------------
Texas Legislation enacted in 1999 provides the framework and timetable to allow
retail electricity competition for all Texas customers. On January 1, 2002,
customer choice of electricity supplier began in the ERCOT area of Texas.
Customer choice has been delayed in the SPP area of Texas until at least January
1, 2007. TCC and TNC operate in ERCOT while SWEPCo and a small portion of TNC's
business is in SPP.
The Texas Legislation, among other things:
o provides for the recovery of stranded generation plant costs,
generation-related regulatory assets and other generation true-up
amounts 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 Texas Legislation also required vertically integrated utilities to legally
separate their generation and retail-related assets from their transmission and
distribution-related assets. Prior to 2002, TCC and TNC functionally separated
their operations. AEP formed new subsidiaries to act as affiliated REPs for TCC
and TNC effective January 1, 2002 (the start date of retail competition). In
December 2002, AEP sold its two affiliated price-to-beat REPs to an unaffiliated
company.
TEXAS TRUE-UP PROCEEDINGS
- -------------------------
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 (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.
The PUCT adopted a rule in 2003 regarding the timing of the True-up Proceedings
scheduling TCC's filing in September 2004 or 60 days after the completion of the
sale of TCC's generation assets, if later. TNC filed its true-up request in June
2004 and updated the filing in October 2004. Due to regulatory and contractual
delays in the sale of its generating assets, TCC has not filed its true-up
request.
True-up Net Regulatory Asset (Liability) Recorded at September 30, 2004:
- ------------------------------------------------------------------------ TCC TNC
--- ---
(in millions)
Components of Net Stranded Generation Costs:
Stranded Generation Plant Costs $1,079 $-
Unsecuritized Transition Generation Regulatory Asset 249 -
Unrefunded Excess Earnings (15) -
Other (56) -
------- -----
Net Stranded Generation Costs 1,257 -
------- -----
Components of Other Recoverable True-up Amounts:
Wholesale Capacity Auction True-up 480 -
Retail Clawback (a) (60) (14)
Deferred Over-recovered Fuel Balance (210) (7)
------- -----
Other Recoverable True-up Amounts 210 (21)
------- -----
Total Recorded Net True-up Regulatory Asset (Liability) $1,467 $(21)
======= =====
(a) Only half of these amounts are actually recorded as regulatory liabilities, as the other half are the responsibility of the
unaffiliated company that owns the affiliated price-to-beat REP.
See discussion below of the above amounts.
Net Stranded Generation Costs
- -----------------------------
The Texas Restructuring Legislation required utilities with stranded generation
plant costs to use market-based methods to value certain generation assets for
determining stranded generation plant costs. TCC is the only AEP subsidiary that
has stranded generation plant costs under the Texas Legislation. TCC elected to
use the sale of assets method to determine the market value of TCC's generation
assets for determining stranded generation plant costs. For purposes of the
True-up Proceeding, the amount of stranded generation plant costs under this
market valuation methodology will be the amount by which the book value of TCC's
generation assets exceeds the market value of the generation assets as measured
by the net proceeds from the sale of the assets. Based on the prices established
by the generation asset sales, discussed below, TCC recorded a net regulatory
asset of $1.1 billion for its stranded generation plant costs from the sale of
TCC's generation assets as shown in the table above, before accrual of any
applicable carrying charges discussed below.
In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's
generation capacity in Texas. We received bids for all of TCC's generation
plants. In January 2004, TCC agreed to sell its 7.81% ownership interest in the
Oklaunion Power Station to an unaffiliated third party for approximately $43
million. In March 2004, TCC agreed to sell its 25.2% ownership interest in STP
for approximately $333 million and its other coal, gas and hydro plants for
approximately $430 million to unaffiliated entities. Each sale is subject to
specified price adjustments. TCC sent right of first refusal notices to the
co-owners of Oklaunion and STP. TCC filed for FERC approval of the sales of
Oklaunion, STP and the fossil and hydro plants. We received a notice from
co-owners of Oklaunion and STP exercising their right of first refusal;
therefore, SEC approval will be required. The original unaffiliated third party
purchaser of Oklaunion has petitioned for a court order declaring its contract
valid and the co-owners' rights of first refusal void. The sale of STP will also
require approval from the Nuclear Regulatory Commission. On July 1, 2004, TCC
completed the sale of the other coal, gas and hydro plants for approximately
$425 million, net of adjustments. The closings of the sales of STP and Oklaunion
plants are expected to occur in the first half of 2005, subject to clarification
of the rights of first refusal and the necessary regulatory approvals. In
addition, there could be delays in resolving litigation with a third party
affecting Oklaunion. In order to sell these assets, TCC defeased all of its
remaining outstanding first mortgage bonds in May 2004. In December 2003, we
recognized as a regulatory asset an estimated impairment from the sale of TCC's
generation assets. TCC is considering seeking a good cause exception to the
true-up rule to allow TCC to make its true-up filing prior to the closings of
the sales of all the generation assets.
In addition to its $1.1 billion of stranded generation plant costs, the Texas
legislation permits TCC to recover its remaining unsecuritized net transition
generation regulatory assets of $249 million less a regulatory liability for the
unrefunded excess earnings of $15 million, discussed below. With other
adjustments, TCC's recorded net stranded generation costs total $1.3 billion.
Unrefunded Excess Earnings
- --------------------------
The Texas Legislation provides for the calculation of excess earnings for each
year from 1999 through 2001. The total excess earnings determined by the PUCT
for this three-year period were $3 million for SWEPCo, $47 million for TCC and
$19 million for TNC. TCC, TNC and SWEPCo challenged the PUCT's treatment of
fuel-related deferred income taxes and appealed the PUCT's final 2000 excess
earnings to the Travis County District Court which upheld the PUCT ruling. After
appealing the District Court ruling upholding the PUCT decision, the Third Court
of Appeals reversed the PUCT order and the District Court's judgment. The
District Court remanded to the PUCT an appeal of the same issue from the PUCT's
2001 order upon agreement of the parties after issuance of the Third Court of
Appeals decision. On September 14, 2004, the parties to the PUCT remand reached
an agreement, which changed the method for calculating excess earnings, which,
in turn, revised the calculation for 2000 and 2001 consistent with the ruling
of the court. Revised excess earnings for the three-year period were
approximately $3 million for SWEPCo, $42 million for TCC and $15 million for
TNC. The PUCT issued a final order approving the agreement in October 2004.
Since an expense and regulatory liability had been accrued in prior years in
compliance with the PUCT orders, the companies reversed a portion of their
regulatory liability for the years 2000 and 2001 consistent with the Appeals
Court's decision and credited amortization expense during the third quarter of
2003. Under the Texas legislation since TNC and SWEPCo do not have stranded
generation plant cost, excess earnings have been applied to reduce T&D capital
expenditures.
In 2001, the PUCT issued an order requiring TCC to return estimated excess
earnings by reducing distribution rates by approximately $55 million plus
accrued interest over a five-year period beginning January 1, 2002. Since excess
earnings amounts were expensed in 1999, 2000 and 2001, the order had no
additional effect on reported net income but reduces cash flows over the refund
period. The remaining $15 million to be refunded is recorded as a regulatory
liability at September 30, 2004 and can be included as a reduction to TCC's
stranded generation plant costs. Management believes that TCC has stranded costs
and that it was, therefore, inconsistent with the Texas restructuring
legislation for the PUCT to order a refund prior to TCC's True-up Proceeding.
TCC appealed the PUCT's premature refund of excess earnings to the Travis County
District Court. That court affirmed the PUCT's decision and further ordered that
the refunds be provided to ultimate customers. TCC has appealed the decision to
the Third Court of Appeals.
Carrying Charges on Recoverable Stranded Costs
- ----------------------------------------------
In December 2001, the PUCT issued a rule concerning stranded cost true-up
proceedings stating, among other things, that carrying costs on stranded costs
would begin to accrue on the date that the PUCT issued its final order in the
True-up Proceeding. TCC and one other Texas electric utility company filed a
direct appeal of the rule to the Texas Third Court of Appeals contending that
carrying costs should commence on January 1, 2002, the day that retail customer
choice began in ERCOT.
The Third Court of Appeals ruled against the utilities, who then appealed to the
Texas Supreme Court. On June 18, 2004, the Texas Supreme Court reversed the
decision of the Third Court of Appeals determining that a carrying cost should
be accrued beginning January 1, 2002 and remanded the proceeding to the PUCT for
further consideration. The Supreme Court determined that utilities with stranded
costs are not permitted to over-recover stranded costs and the PUCT should
address whether any portion of the 2002 and 2003 wholesale capacity auction
true-up regulatory asset includes a recovery of stranded costs or carrying costs
on stranded costs. A motion for rehearing with the Supreme Court was denied and
the ruling is final.
The PUCT in September 2004 considered the Supreme Court's decision in true-up
hearings held for another utility, CenterPoint Energy, Inc. (CenterPoint). In
that case while the PUCT has indicated preliminary positions regarding the
methodology to calculate recoverable carrying costs, uncertainties exist as to
the ultimate methodology that will be adopted by the PUCT in its final order.
The final order in the CenterPoint case is expected to be issued later in
November 2004. If the final order in the CenterPoint case resolves the existing
uncertainties, TCC will record a carrying cost back to January 1, 2002 in the
fourth quarter of 2004 as an increase to its net true-up regulatory asset.
At this time we are unable to determine the amount of such carrying cost pending
receipt of the final CenterPoint order.
Wholesale Capacity Auction True-up
- ----------------------------------
The Texas Legislation required that electric utilities and their affiliated
power generation companies (PGC) offer for sale at auction, in 2002, 2003 and
thereafter, at least 15% of the PGC's Texas jurisdictional installed generation
capacity in order to promote competitiveness in the wholesale market through
increased availability of generation. Actual market power prices received in the
state-mandated auctions are used to calculate the wholesale capacity auction
true-up revenues for the True-up Proceeding. According to PUCT rules, the
wholesale capacity auction true-up is only applicable to the years 2002 and
2003. TCC recorded a $480 million regulatory asset and related revenues which
represent the quantifiable amount of the wholesale capacity auction true-up for
the years 2002 and 2003.
In the true-up proceeding of CenterPoint, while the PUCT has indicated
preliminary positions regarding modifications of the calculation of the
wholesale capacity auction true-up reflecting CenterPoint's specific facts and
circumstances, uncertainties exist as to the ultimate modifications and
calculations that will be adopted by the PUCT in its final order and if TCC's
facts and circumstances will result in similar results in its true-up
proceeding. Specifically, the PUCT is evaluating 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. Upon
issuance of a final written order in the CenterPoint case, management will
evaluate the order and, if appropriate, record a provision for any amount that
is no longer probable of recovery as a result of final decisions in the order
which are applicable to TCC. The CenterPoint order is expected to be issued
later in November 2004.
Retail Clawback
- ---------------
The Texas Legislation provides for the affiliated price-to-beat (PTB) retail
electric providers (REPs) serving residential and small commercial customers to
refund to its T&D utility the excess of the PTB revenues over market prices
(subject to certain conditions and a limitation of $150 per customer). This is
the retail clawback. If, prior to January 1, 2004, 40% of the load for the
residential or small commercial classes is served by competitive REPs, the
retail clawback is not applicable for that class of customer. During 2003, TCC
and TNC filed to notify the PUCT that competitive REPs serve over 40% of the
load in the small commercial class. The PUCT approved TCC's and TNC's filings in
December 2003. In 2002, AEP had accrued a regulatory liability of approximately
$9 million for the small commercial retail clawback on its REP's books. When the
PUCT certified that the REP's in TCC and TNC service territories had reached the
40% threshold, the regulatory liability was no longer required for the small
commercial class and was reversed in December 2003. Based upon customer
information filed by the unaffiliated company which operates as the
price-to-beat REP for TCC and TNC, we updated the estimated residential retail
clawback regulatory liability in May 2004. At September 30, 2004, TCC's retail
clawback regulatory liability was $30 million and TNC's was $7 million.
Fuel Balance Recoveries
- -----------------------
In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail sales
within its ERCOT service area for inclusion in the True-up Proceeding. In
January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation
case. The PUCT issued a written order in March 2004. Various parties, including
TNC, requested rehearing of the PUCT's order. In May 2004, the PUCT reversed
certain prior rulings which resulted in an over-recovered balance of $7 million.
In October 2004, the PUCT issued a final order which resulted in a reduction in
the over-recovery balance to $4 million. TNC filed an update to its true-up
filing to reflect the PUCT's final order in October 2004.
In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its
deferred over-recovery fuel balance for inclusion in the True-up Proceeding. In
May 2004, the PUCT remanded TCC's fuel proceeding to the ALJ to consider
additional evidence on one issue. TCC has provided for a $210 million
over-recovery balance at September 30, 2004. Management believes that TCC has
provided for all probable to-date disallowances pending the remand and receipt
of a final order. However, due to the remand, management is unable to predict
the amount of any additional disallowances of TCC's final fuel over-recovery
balance which will be included in its True-up Proceeding until the remand is
completed and a final order issued.
See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 3 "Rate Matters"
for further discussion.
Stranded Cost Recovery
- ----------------------
When the True-up Proceeding is completed, TCC intends to file to recover
PUCT-approved net stranded generation costs and other true-up amounts, plus
appropriate carrying charges, through a non-bypassable competition transition
charge in the regulated T&D rates. TCC intends to seek to securitize the
approved net stranded generation costs plus related carrying costs. The annual
costs of securitization are recovered through a non-bypassable transition charge
collected by the T&D utility over the term of the securitization bonds. The
other approved net true-up items will be recovered or refunded through a
non-bypassable competition transition wires charge or credit.
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. We
expect that TCC's True-up Proceeding filing will seek to recover an amount in
excess of the total of its recorded net regulatory asset through September 30,
2004. This is primarily due to the fact that TCC has not been able to accrue a
carrying cost to date as a result of uncertainties that exist. Management
expects to be able to record a carrying cost in the fourth quarter of 2004 based
on the final order in the CenterPoint case.
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 possibly 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.
TNC 2004 True-up Filing
- -----------------------
In June 2004, TNC filed its True-up Proceeding including the fuel reconciliation
balance and the retail clawback calculation. The amount of the deferred over
recovered fuel balance recorded at September 30, 2004 was approximately $7
million. The retail clawback regulatory liability included in the filing was
adjusted in the second quarter of 2004 to $7 million (TNC's allocated portion of
the REPs' retail clawback) reflecting the number of customers served on January
1, 2004. TNC filed an update to the true-up filing to reflect the final order in
its fuel reconciliation proceeding in October 2004 which adjusted its
over-recovery balance to $4.7 million inclusive of interest.
VIRGINIA RESTRUCTURING
- ----------------------
In April 2004, the Governor of Virginia signed legislation which extends the
transition period for electricity restructuring, including capped rates, through
December 31, 2010. The legislation provides specified cost recovery
opportunities during the capped rate period, including two optional general base
rate changes and an opportunity for timely recovery, through a separate rate
mechanism, of certain incremental environmental and reliability costs incurred
on and after July 1, 2004.
5. COMMITMENTS AND CONTINGENCIES
-----------------------------
As discussed in the Commitments and Contingencies note within our 2003 Annual
Report, we continue to be involved in various legal matters. The 2003 Annual
Report should be read in conjunction with this report in order to understand the
other material nuclear and operational matters without significant changes since
our disclosure in the 2003 Annual Report. The material matters discussed in the
2003 Annual Report without significant changes in status since year-end include,
but are not limited to, (1) nuclear matters, (2) construction commitments, (3)
potential uninsured losses, (4) California lawsuits, (5) Bank of Montreal Claim,
and (6) FERC proposed Standard Market Design. See disclosure below for
significant matters with changes in status subsequent to the disclosure made in
our 2003 Annual Report.
Environmental
- -------------
Federal EPA Complaint and Notice of Violation
- ---------------------------------------------
The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and
other unaffiliated utilities modified certain units at coal-fired generating
plants in violation of the new source review requirements of the Clean Air Act
(CAA). The Federal EPA filed its complaints against our subsidiaries in U.S.
District Court for the Southern District of Ohio. The court also consolidated a
separate lawsuit, initiated by certain special interest groups, with the Federal
EPA case. The alleged modifications relate to costs that were incurred at our
generating units over a 20-year period.
Under the CAA, if a plant undertakes a major modification that directly results
in an emissions increase, permitting requirements might be triggered and the
plant may be required to install additional pollution control technology. This
requirement does not apply to activities such as routine maintenance,
replacement of degraded equipment or failed components, or other repairs needed
for the reliable, safe and efficient operation of the plant. The CAA authorizes
civil penalties of up to $27,500 per day per violation at each generating unit
($25,000 per day prior to January 30, 1997). In 2001, the District Court ruled
claims for civil penalties based on activities that occurred more than five
years before the filing date of the complaints cannot be imposed. There is no
time limit on claims for injunctive relief.
On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to
"perfect" its complaint in the pending litigation. The NOV expands the number of
alleged "modifications" undertaken at the Muskingum River, Cardinal, Conesville
and Tanners Creek plants during scheduled outages on these units from 1979
through the present. Approximately one-third of the allegations in the NOV are
already contained in allegations made by the states or the special interest
groups in the pending litigation. The Federal EPA filed a motion to amend its
complaint and to expand the scope of the pending litigation. The AEP
subsidiaries opposed that motion. In September 2004, the judge disallowed the
addition of claims to the pending case. The judge also granted motions to
dismiss a number of allegations in the original filing.
On August 7, 2003, the District Court issued a decision following a liability
trial in a case pending in the Southern District of Ohio against Ohio Edison
Company, an unaffiliated utility. The District Court held that replacements of
major boiler and turbine components that are infrequently performed at a single
unit, that are performed with the assistance of outside contractors, that are
accounted for as capital expenditures, and that require the unit to be taken out
of service for a number of months are not "routine" maintenance, repair, and
replacement. The District Court also held that a comparison of past actual
emissions to projected future emissions must be performed prior to any
non-routine physical change in order to evaluate whether an emissions increase
will occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all of the
challenged activities in that case were not routine, and that the changes
resulted in significant net increases in emissions for certain pollutants. A
remedy trial was scheduled for July 2004, but has been postponed until January
2005 to facilitate further settlement negotiations.
Management believes that the Ohio Edison decision fails to properly evaluate and
apply the applicable legal standards. The facts in our case also vary widely
from plant to plant. Further, the Ohio Edison decision is limited to liability
issues, and provides no insight as to the remedies that might ultimately be
ordered by the Court.
On August 26, 2003, the District Court for the Middle District of South Carolina
issued a decision on cross-motions for summary judgment prior to a liability
trial in a case pending against Duke Energy Corporation, an unaffiliated
utility. The District Court denied all the pending motions, but set forth the
legal standards that will be applied at the trial in that case. The District
Court determined that the Federal EPA bears the burden of proof on the issue of
whether a practice is "routine maintenance, repair, or replacement" and on
whether or not a "significant net emissions increase" results from a physical
change or change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the relevant
source category" in determining if it is "routine." Further, the Federal EPA
must calculate emissions by determining first whether a change in the maximum
achievable hourly emission rate occurred as a result of the change, and then
must calculate any change in annual emissions holding hours of operation
constant before and after the change. The Federal EPA requested reconsideration
of this decision, or in the alternative, certification of an interlocutory
appeal to the Fourth Circuit Court of Appeals, and the District Court denied the
Federal EPA's motion. On April 13, 2004, the parties filed a joint motion for
entry of final judgment, based on stipulations of relevant facts that obviated
the need for a trial, but preserving plaintiffs' right to seek an appeal of the
federal prevention of significant deterioration (PSD) claims. On April 14, 2004,
the Court entered final judgment for Duke Energy on all of the PSD claims made
in the amended complaints, and dismissed all remaining claims with prejudice.
The United States subsequently filed a notice of appeal to the Fourth Circuit
Court of Appeals. The case was briefed in September 2004.
On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued
an order invalidating the administrative compliance order issued by the Federal
EPA to the Tennessee Valley Authority for alleged CAA violations. The 11th
Circuit determined that the administrative compliance order was not a final
agency action, and that the enforcement provisions authorizing the issuance and
enforcement of such orders under the CAA are unconstitutional. The United States
filed a petition for certiorari with the United States Supreme Court and on May
3, 2004, that petition was denied.
On June 26, 2003, the United States Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG),
of which our subsidiaries are members, to reopen petitions for review of the
1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA
claims in our case and other related cases. On August 4, 2003, UARG filed a
motion to separate and expedite review of their challenges to the 1980 and 1992
rulemakings from other unrelated claims in the consolidated appeal. The Circuit
Court denied that motion on September 30, 2003. The central issue in these
petitions concerns the lawfulness of the emissions increase test, as currently
interpreted and applied by the Federal EPA in its utility enforcement actions. A
decision by the D. C. Circuit Court could significantly impact further
proceedings in our case. Briefing continues in this case and oral argument is
scheduled for January 2005.
On August 27, 2003, the Administrator of the Federal EPA signed a final rule
that defines "routine maintenance repair and replacement" to include
"functionally equivalent equipment replacement." Under the new final rule,
replacement of a component within an integrated industrial operation (defined as
a "process unit") with a new component that is identical or functionally
equivalent will be deemed to be a "routine replacement" if the replacement does
not change any of the fundamental design parameters of the process unit, does
not result in emissions in excess of any authorized limit, and does not cost
more than twenty percent of the replacement cost of the process unit. The new
rule is intended to have a prospective effect, and was to become effective in
certain states 60 days after October 27, 2003, the date of its publication in
the Federal Register, and in other states upon completion of state processes to
incorporate the new rule into state law. On October 27, 2003, twelve states, the
District of Columbia and several cities filed an action in the United States
Court of Appeals for the District of Columbia Circuit seeking judicial review of
the new rule. The UARG has intervened in this case. On December 24, 2003, the
Circuit Court granted a motion from the petitioners to stay the effective date
of this rule, which had been December 26, 2003.
We are unable to estimate the loss or range of loss related to any contingent
liability we might have for civil penalties under the CAA proceedings. We are
also unable to predict the timing of resolution of these matters due to the
number of alleged violations and the significant number of issues yet to be
determined by the Court. If we do not prevail, any capital and operating costs
of additional pollution control equipment that may be required, as well as any
penalties imposed, would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity.
In December 2000, Cinergy Corp., an unaffiliated utility, which operates certain
plants jointly owned by CSPCo, reached a tentative agreement with the Federal
EPA and other parties to settle litigation regarding generating plant emissions
under the Clean Air Act. Negotiations are continuing between the parties in an
attempt to reach final settlement terms. Cinergy's settlement could impact the
operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned
25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached,
CSPCo will be unable to determine the settlement's impact on its jointly owned
facilities and its future results of operations and cash flows.
On July 21, 2004, the Sierra Club issued a notice of intent to file a citizen
suit claim against DPL, Inc., Cinergy Corporation, CSPCo, and The Dayton Power &
Light Company for alleged violations of the New Source Review programs at the
Stuart Station. CSPCo owns a 26% share of the Stuart Station. On September 21,
2004, the Sierra Club filed a complaint under the citizen suit provisions of the
CAA in the United States District Court for the Southern District of Ohio
alleging that violations of the PSD and New Source Performance Standards
requirements of the CAA and the opacity provisions of the Ohio state
implementation plan occurred at the J.M. Stuart Station, and seeking injunctive
relief and civil penalties. We believe the allegations in the complaint are
without merit, and intend to defend vigorously this action. Management is unable
to predict the timing of any future action by the special interest group or the
effect of such actions on future operations or cash flows.
SWEPCo Notice of Enforcement and Notice of Citizen Suit
- -------------------------------------------------------
On July 13, 2004, two special interest groups issued a notice of intent to
commence a citizen suit under the Clean Air Act for alleged violations of
various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and
Pirkey plants. This notice was prompted by allegations made by a terminated AEP
employee. The allegations at the Welsh Plant concern compliance with emission
limitations on particulate matter and carbon monoxide, compliance with a
referenced design heat input value, and compliance with certain reporting
requirements. The allegations at the Knox Lee Plant relate to the receipt of an
off-specification fuel oil, and the allegations at Pirkey Plant relate to
testing and reporting of volatile organic compound emissions. No action can be
commenced until 60 days after the date of notice.
On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a
Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary
of findings resulting from a compliance investigation at the plant. The summary
includes allegations concerning compliance with certain recordkeeping and
reporting requirements, compliance with a referenced design heat input value in
the Welsh permit, compliance with a fuel sulfur content limit, and compliance
with emission limits for sulfur dioxide.
On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to
the off-specification fuel oil deliveries at the Knox Lee Plant. On August 30,
2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the reporting of
volatile organic compound emissions at the Pirkey Plant.
SWEPCo has previously reported to the TCEQ, deviations related to the receipt of
off-specification fuel at Knox Lee, the volatile organic compound emissions at
Pirkey, and the referenced recordkeeping and reporting requirements and heat
input value at Welsh. We are preparing additional responses to the Notice of
Enforcement and the notice from the special interest groups. Management is
unable to predict the timing of any future action by TCEQ or the special
interest groups or the effect of such actions on results of operations,
financial condition or cash flows.
Carbon Dioxide Public Nuisance Claims
- -------------------------------------
On July 21, 2004, attorneys general from eight states and the corporation
counsel for the City of New York filed an action in federal district court for
the Southern District of New York against AEP, AEPSC and four other unaffiliated
governmental and investor-owned electric utility systems. That same day, a
similar complaint was filed in the same court against the same defendants by the
Natural Resources Defense Council on behalf of two special interest groups. The
actions allege that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts associated
with global warming, and seek injunctive relief in the form of specific emission
reduction commitments from the defendants. In September 2004, the defendants,
including AEP and AEPSC, filed a motion to dismiss the lawsuits. Management
believes the actions are without merit and intends to defend vigorously against
the claims.
Nuclear Decommissioning
- -----------------------
As discussed in the 2003 Annual Report, decommissioning costs are accrued over
the service life of STP. The licenses to operate the two nuclear units at STP
expire in 2027 and 2028. TCC had estimated its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of approximately $8 million per year.
In May 2004, an updated decommissioning study was completed for STP. The study
estimates TCC's share of the decommissioning costs of STP to be $344 million in
nondiscounted 2004 dollars. We are currently analyzing the STP study to
determine the effect on our asset retirement obligations (ARO) and will make any
appropriate adjustments to the ARO liability and related regulatory asset in the
fourth quarter 2004. As discussed in Note 7, TCC is in the process of selling
its ownership interest in STP to a non-affiliate, and upon completion of the
sale it is anticipated that TCC will no longer be obligated for nuclear
decommissioning liabilities associated with STP.
Operational
- -----------
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 our 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 our 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's
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.
Merger Litigation
- -----------------
In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the
SEC failed to adequately explain that the June 15, 2000 merger of AEP with CSW
meets the requirements of the PUHCA and sent the case back to the SEC for
further review. Specifically, the court told the SEC to revisit the basis for
its conclusion that the merger met PUHCA requirements that utilities be
"physically interconnected" and confined to a "single area or region." In August
2004 the SEC announced it would conduct hearings on this issue. The hearing is
scheduled for January 2005.
In its June 2000 approval of the merger, the SEC agreed with AEP that the
companies' systems are integrated because they have transmission access rights
to a single high-voltage line through Missouri and also met the PUHCA's single
region requirement. In its ruling, the appeals court said that the SEC failed to
support and explain its conclusions that the interconnection and single region
requirements are satisfied.
Management believes that the merger meets the requirements of the PUHCA and
expects the matter to be resolved favorably.
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 trading accounts
receivables and payables with Enron. In addition, on June 1, 2001, we purchased
HPL from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.
Enron Bankruptcy - Bammel storage facility and HPL indemnification matters - In
connection with the 2001 acquisition of HPL, we entered into a prepaid
arrangement under which we acquired exclusive rights to use and operate the
underground Bammel gas storage facility and appurtenant pipelines pursuant to an
agreement with BAM Lease Company. This exclusive right to use the referenced
facility is for a term of 30 years, with a renewal right for another 20 years.
In January 2004, we filed an amended lawsuit against Enron and its subsidiaries
in the U.S. Bankruptcy Court claiming that Enron did not have the right to
reject the Bammel storage facility agreement or the cushion gas use agreement,
described below. In April 2004, AEP and Enron entered into a settlement
agreement under which we will acquire title to the Bammel gas storage facility
and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF)
of natural gas currently used as cushion gas for $115 million. AEP and Enron
will mutually release each other from all claims associated with the Bammel
facility, including our indemnity claims. The settlement received Bankruptcy
Court approval on September 30, 2004 and is expected to close in the fourth
quarter 2004. The parties' respective trading claims and Bank of America's (BOA)
purported lien on approximately 55 BCF of natural gas in the Bammel storage
reservoir (as described below) are not covered by the settlement agreement.
Enron Bankruptcy - Right to use of cushion gas agreements - In connection with
the 2001 acquisition of HPL, we also entered into an agreement with BAM Lease
Company, which grants HPL the exclusive right to use approximately 65 BCF of
cushion gas (the 10.5 BCF and 55 BCF described in the preceding paragraph)
required for the normal operation of the Bammel gas storage facility. At the
time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate)
and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of
cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate
also released HPL from all prior and future liabilities and obligations in
connection with the financing arrangement.
After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported
default by Enron under the terms of the financing arrangement. In July 2002, the
BOA Syndicate filed a lawsuit against HPL in the state court of Texas seeking a
declaratory judgment that the BOA Syndicate has a valid and enforceable security
interest in gas purportedly in the Bammel storage reservoir. In December 2003,
the Texas state court granted partial summary judgment in favor of the BOA
Syndicate. HPL appealed this decision. In June 2004, BOA filed an amended
petition in a separate lawsuit in Texas state court seeking to obtain possession
of up to 55 BCF of storage gas in the Bammel storage facility or its fair value.
Following an adverse decision on its motion to obtain possession of this gas,
BOA voluntarily dismissed this action. In October 2004, BOA refiled this action.
HPL filed a motion to have the case assigned to the judge who heard the case
originally and that motion was granted. HPL intends to defend vigorously against
BOA's claims.
In October 2003, AEP filed a lawsuit against BOA in the United States District
Court for the Southern District of Texas. BOA led a lending syndicate involving
the 1997 gas monetization that Enron and its subsidiaries undertook and the
leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit
asserts that BOA made misrepresentations and engaged in fraud to induce and
promote the stock sale of HPL, that BOA directly benefited from the sale of HPL
and that AEP undertook the stock purchase and entered into the Bammel storage
facility lease arrangement with Enron and the cushion gas arrangement with Enron
and BOA based on misrepresentations that BOA made about Enron's financial
condition that BOA knew or should have known were false including that the 1997
gas monetization did not contravene or constitute a default of any federal,
state, or local statute, rule, regulation, code or any law. In February 2004,
BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the
Magistrate Judge issued a Recommended Decision and Order recommending that BOA's
Motion to Dismiss be denied, that the five counts in the lawsuit seeking
declaratory judgments involving the Bammel reservoir and the right to use and
cushion gas consent agreements be transferred to the Southern District of New
York and that the four counts alleging breach of contract, fraud and negligent
misrepresentation proceed in the Southern District of Texas. BOA has objected to
the Magistrate Judge's decision and the matter is now before the District Judge.
In February 2004, in connection with BOA's dispute, Enron filed Notices of
Rejection regarding the cushion gas exclusive right to use agreement and other
incidental agreements. We have objected to Enron's attempted rejection of these
agreements.
Enron Bankruptcy - Commodity trading settlement disputes - In September 2003,
Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP's
offsetting of receivables and payables and related collateral across various
Enron entities and seeking payment of approximately $125 million plus interest
in connection with gas-related trading transactions. AEP has asserted its right
to offset trading payables owed to various Enron entities against trading
receivables due to several AEP subsidiaries. The parties are currently in
non-binding court-sponsored mediation.
In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC
seeking approximately $93 million plus interest in connection with a transaction
for the sale and purchase of physical power among Enron, AEP and Allegheny
Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the
effects of the transaction. AEP believes it has several defenses to the claims
in the action being brought by Enron. The parties are currently in non-binding
court-sponsored mediation.
Enron Bankruptcy - Summary - The amount expensed in prior years in connection
with the Enron bankruptcy was based on an analysis of contracts where AEP and
Enron entities are counterparties, the offsetting of receivables and payables,
the application of deposits from Enron entities and management's analysis of the
HPL related purchase contingencies and indemnifications. As noted above, Enron
has challenged our offsetting of receivables and payables and there is a dispute
regarding the cushion gas agreement. Although management is unable to predict
the outcome of these lawsuits, it is possible that their resolution could have
an adverse impact on our results of operations, cash flows or financial
condition.
Shareholder Lawsuits
- --------------------
In the fourth quarter of 2002 and the first quarter of 2003, lawsuits alleging
securities law violations and seeking class action certification were filed in
federal District Court, Columbus, Ohio against AEP, certain AEP executives, and
in some of the lawsuits, members of the AEP Board of Directors and certain
investment banking firms. The lawsuits claim that we failed to disclose that
alleged "round trip" trades resulted in an overstatement of revenues, that we
failed to disclose that our traders falsely reported energy prices to trade
publications that published gas price indices and that we failed to disclose
that we did not have in place sufficient management controls to prevent "round
trip" trades or false reporting of energy prices. The plaintiffs sought recovery
of an unstated amount of compensatory damages, attorney fees and costs. The
Court appointed a lead plaintiff who filed a Consolidated Amended Complaint. We
filed a Motion to Dismiss the Consolidated Amended Complaint. Also, in the first
quarter of 2003, a lawsuit making essentially the same allegations and demands
was filed in state Common Pleas Court, Columbus, Ohio against AEP, certain
executives, members of the Board of Directors and our independent auditor. We
removed this case to federal District Court in Columbus and the Court denied
plaintiff's motion to remand the case to state court. In September 2004, the
U.S. District Court Judge dismissed the cases and expressly denied the
plaintiffs' request for an opportunity to file amended complaints with new or
revised allegations. Plaintiffs did not appeal this decision.
In the fourth quarter of 2002, two shareholder derivative actions were filed in
state court in Columbus, Ohio against AEP and its Board of Directors alleging a
breach of fiduciary duty for failure to establish and maintain adequate internal
controls over our gas trading operations. These cases have been stayed pending
the outcome of our Motion to Dismiss the Consolidated Amended Complaint in the
federal securities lawsuits. In October 2004 plaintiffs agreed to dismiss these
cases. Also, in the fourth quarter of 2002 and the first quarter of 2003, three
putative class action lawsuits were filed against AEP, certain AEP executives
and AEP's Employee Retirement Income Security Act (ERISA) Plan Administrator
alleging violations of ERISA in the selection of AEP stock as an investment
alternative and in the allocation of assets to AEP stock. The ERISA actions
are pending in federal District Court, Columbus, Ohio. In these actions, the
plaintiffs seek recovery of an unstated amount of compensatory damages,
attorney fees and costs. We filed a Motion to Dismiss these actions, which the
Court denied. We have filed a Motion for Leave to file an interlocutory appeal
seeking review of part of the Court's decision. The cases are in the discovery
stage. We intend to continue to defend vigorously against these claims.
Cornerstone Lawsuit
- -------------------
In the third quarter of 2003, Cornerstone Propane Partners filed an action in
the United States District Court for the Southern District of New York against
forty companies, including AEP and AEPES seeking class certification and
alleging unspecified damages from claimed price manipulation of natural gas
futures and options on the NYMEX from January 2000 through December 2002.
Thereafter, two similar actions were filed in the same court against a number of
companies including AEP and AEPES making essentially the same claims as
Cornerstone Propane Partners and also seeking class certification. On December
5, 2003, the Court issued its initial Pretrial Order consolidating all related
cases, appointing co-lead counsel and providing for the filing of an amended
consolidated complaint. In January 2004, plaintiffs filed an amended
consolidated complaint. We and the other defendants filed a motion to dismiss
the complaint which the Court denied in September 2004. We intend to defend
vigorously against these claims.
Texas Commercial Energy, LLP Lawsuit
- ------------------------------------
Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider (REP),
filed a lawsuit in federal District Court in Corpus Christi, Texas, in July
2003, against us and four of our subsidiaries, certain unaffiliated energy
companies and ERCOT. The action alleges violations of the Sherman Antitrust Act,
fraud, negligent misrepresentation, breach of fiduciary duty, breach of
contract, civil conspiracy and negligence. The allegations, not all of which are
made against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price spikes
requiring TCE to post additional collateral and ultimately forced it into
bankruptcy when it was unable to raise prices to its customers due to fixed
price contracts. The suit alleges over $500 million in damages for all
defendants and seeks recovery of damages, exemplary damages and court costs. Two
additional parties, Utility Choice, LLC and Cirro Energy Corporation, have
sought leave to intervene as plaintiffs asserting similar claims. We filed a
Motion to Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. We filed a Motion to Dismiss the amended complaint. In June 2004, the
Court dismissed all claims against the AEP companies. TCE has appealed the trial
court's decision to the United States Court of Appeals for the Fifth Circuit.
Energy Market Investigation
- ---------------------------
AEP and other energy market participants received data requests, subpoenas and
requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity
Futures Trading Commission (CFTC), the U.S. Department of Justice and the
California attorney general during 2002. Management responded to the inquiries
and provided the requested information and has continued to respond to
supplemental data requests in 2003 and 2004.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in
federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES
provided false or misleading information about market conditions and prices of
natural gas in an attempt to manipulate the price of natural gas in violation of
the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and
disgorgement of benefits. We responded to the complaint in September 2004. In
2003 we recorded a provision related to these matters. We have engaged in
settlement discussions with several agencies and are evaluating whether to
conclude settlements in order to put these investigations behind us even though
we believe we have meritorious legal positions and defenses. If we elect to
settle all matters, the payments could exceed the 2003 provision and could have
a material impact on our 2004 earnings and cash flows.
FERC Market Power Mitigation
- ----------------------------
In April 2004, the FERC issued two orders concerning utilities' ability to sell
wholesale electricity at market-based rates. In the first order, the FERC
adopted two new interim screens for assessing potential generation market power
of applicants for wholesale market based rates, and described additional
analyses and mitigation measures that could be presented if an applicant does
not pass one of these interim screens. These two screening tests include a
"pivotal supplier" test which determines if the market load can be fully served
by alternative suppliers and a "market share" test which compares the amount of
surplus generation at the time of the applicant's minimum load. In July 2004,
the FERC issued an order on rehearing affirming its conclusions in the April
order and directing AEP and two unaffiliated utilities to file generation market
power analyses within 30 days. In the second order, the FERC initiated a
rulemaking to consider whether the FERC's current methodology for determining
whether a public utility should be allowed to sell wholesale electricity at
market-based rates should be modified in any way.
On August 9, 2004, AEP submitted its Market Power Analysis pursuant to the
FERC's Orders on Rehearing. The analysis focused on the three major areas in
which AEP serves load and owns generation resources -- ECAR, SPP and ERCOT, and
the "first tier" control areas for each of those areas.
The pivotal supplier and market share screen analyses that AEP filed
demonstrated that AEP does not possess market power in any of the control areas
to which it is directly connected (first-tier markets). AEP passed both
screening tests in all of its "first tier" markets. In its three "home" control
areas, AEP easily passed the pivotal supplier test. AEP, as part of PJM, also
passes the market share screen for the PJM destination market. AEP also passed
the market share screen for ERCOT. AEP did not pass the market share screen as
designed by the FERC for the SPP control area. Consequently, AEP also submitted
substantial additional information, including historical purchase and sales data
that demonstrates that AEP does not possess market power in any of the "home"
destination markets. AEP requested that its existing market-based pricing
authorization in all markets be continued based on this analysis. AEP also
requested that the FERC rule without instituting a proceeding and without
setting a refund date. This case is pending.
6. GUARANTEES
----------
There are certain immaterial liabilities recorded for guarantees entered into
subsequent to December 31, 2002 in accordance with FIN 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness to Others." There is no collateral held in relation
to any guarantees in excess of our ownership percentages and there is no
recourse to third parties in the event any guarantees are drawn unless specified
below.
LETTERS OF CREDIT
- -----------------
We have entered into standby letters of credit (LOC) with third parties. These
LOCs cover gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits, debt service reserves and
credit enhancements for issued bonds. We issued all of these LOCs in our
ordinary course of business. At September 30, 2004, the maximum future payments
for all the LOCs were approximately $202 million with maturities ranging from
October 2004 to January 2011. As the parent of various subsidiaries, we hold all
assets of the subsidiaries as collateral. There is no recourse to third parties
in the event these LOCs are drawn.
GUARANTEES OF THIRD-PARTY OBLIGATIONS
- -------------------------------------
CSW Energy and CSW International
- --------------------------------
CSW Energy and CSW International, our subsidiaries, have guaranteed 50% of the
required debt service reserve of Sweeny Cogeneration L.P. (Sweeny), an IPP of
which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny
funding the debt reserve as a part of a financing. In the event that Sweeny does
not make the required debt payments, CSW Energy and CSW International have a
maximum future payment exposure of approximately $4 million, which expires in
June 2020.
SWEPCo
- ------
In connection with reducing the cost of the lignite mining contract for its
Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain conditions, to
assume the capital lease obligations and term loan payments of the mining
contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under
any of these agreements, SWEPCo's total future maximum payment exposure is
approximately $54 million with maturity dates ranging from June 2005 to February
2012.
As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, SWEPCo has agreed to provide guarantees of mine
reclamation in the amount of approximately $85 million. Since SWEPCo uses
self-bonding, the guarantee provides for SWEPCo to commit to use its resources
to complete the reclamation in the event the work is not completed by a third
party miner. At September 30, 2004, the cost to reclaim the mine in 2035 is
estimated to be approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.
Effective July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN
46. SWEPCo does not have an ownership interest in Sabine.
INDEMNIFICATIONS AND OTHER GUARANTEES
- -------------------------------------
Contracts
- ---------
We entered into several types of contracts which require indemnifications.
Typically these contracts include, but are not limited to, sale agreements,
lease agreements, purchase agreements and financing agreements. Generally these
agreements may include, but are not limited to, indemnifications around certain
tax, contractual and environmental matters. With respect to sale agreements, our
exposure generally does not exceed the sale price. We cannot estimate the
maximum potential exposure for any of these indemnifications entered into prior
to December 31, 2002 due to the uncertainty of future events. In 2003 and during
the first nine months of 2004, we entered into several sale agreements. These
sale agreements include indemnifications with a maximum exposure of
approximately $963 million. There are no material liabilities recorded for any
indemnifications entered during 2003 or the first nine months of 2004. There are
no liabilities recorded for any indemnifications entered prior to December 31,
2002.
Master Operating Lease
- ----------------------
We lease certain equipment under a master operating lease. Under the lease
agreement, the lessor is guaranteed to receive up to 87% of the unamortized
balance of the equipment at the end of the lease term. If the fair market value
of the leased equipment is below the unamortized balance at the end of the lease
term, we have committed to pay the difference between the fair market value and
the unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At September 30, 2004, the maximum potential loss for this
lease agreement was approximately $43 million ($28 million, net of tax) assuming
the fair market value of the equipment is zero at the end of the lease term.
Railcar Lease
- -------------
In June 2003, we entered into an agreement with an unrelated, unconsolidated
leasing company to lease 875 coal-transporting aluminum railcars. The lease has
an initial term of five years and may be renewed for up to three additional
five-year terms, for a maximum of twenty years.
Under the lease agreement, the lessor is guaranteed that the sale proceeds under
a return-and-sale option will equal a minimum lessee obligation amount specified
in the lease, which declines over the term from approximately 86% to 77% of the
projected fair market value of the equipment. At September 30, 2004, the maximum
potential loss was approximately $31.5 million ($20.5 million, net of tax)
assuming the fair market value of the equipment is zero at the end of the
current lease term. The railcars are subleased for one year terms to an
unaffiliated company under an operating lease. The sublessee has recently
renewed for an additional year and may renew the lease for up to three more
additional one-year terms.
7. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE
--------------------------------------------------------------
DISPOSITION COMPLETED DURING FIRST QUARTER 2004
- -----------------------------------------------
Pushan Power Plant (Investments - Other segment)
- ------------------------------------------------
In the fourth quarter of 2002, we began active negotiations to sell our interest
in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest
partner. A purchase and sale agreement was signed in the fourth quarter of 2003.
The sale was completed in March 2004 for $60.7 million. An estimated loss on
disposal of $20 million pre-tax ($13 million after-tax) was recorded in December
2002, based on an indicative price expression at that time, and was classified
in Discontinued Operations. The effect of the sale on the first quarter 2004
results of operations was not significant.
Results of operations of Pushan have been reclassified as Discontinued
Operations. The assets and liabilities of Pushan have been included in Assets of
Discontinued Operations and Held for Sale and Liabilities of Discontinued
Operations and Held For Sale, respectively, on our Consolidated Balance Sheet at
December 31, 2003.
DISPOSITIONS COMPLETED DURING SECOND QUARTER 2004
- -------------------------------------------------
LIG Pipeline Company and its Subsidiaries (Investments - Gas Operations segment)
- --------------------------------------------------------------------------------
As a result of our 2003 decision to exit our non-core businesses, we actively
marketed LIG Pipeline Company which possesses approximately 2,000 miles of
natural gas gathering and transmission pipelines in Louisiana and five gas
processing facilities that straddle the system. For the year ended December 31,
2003, LIG's assets were classified as held for sale and their operations were
shown under Discontinued Operations. In January 2004, a decision was made to
sell LIG's pipeline and processing assets separate from LIG's gas storage
assets. After receiving and analyzing initial bids during the fourth quarter of
2003, we recorded a $133.9 million pre-tax ($99 million after-tax) impairment
loss; of this loss, $128.9 million pre-tax relates to the impairment of goodwill
and $5 million pre-tax relates to other charges. In February 2004, we signed a
definitive agreement to sell LIG Pipeline Company, which owned all of the
pipeline and processing assets of LIG. The sale of LIG Pipeline Company and its
assets for $76.2 million was completed in April 2004 and the impact on results
of operations in the second quarter of 2004 was not significant. The assets and
liabilities of LIG are classified as Assets of Discontinued Operations and Held
for Sale and Liabilities of Discontinued Operations and Held for Sale,
respectively on our Consolidated Balance Sheets at December 31, 2003. The
results of operations (including the above-mentioned impairments and other
related charges) are classified in Discontinued Operations in our Consolidated
Statements of Operations for the periods ending September 30, 2004 and 2003.
AEP Coal (Investments - Other segment)
- --------------------------------------
In 2003, as a result of management's decision to exit our non-core businesses,
we retained an advisor to facilitate the sale of AEP Coal. In March 2004, an
agreement was reached to sell assets, exclusive of certain reserves and related
liabilities, of the mining operations of AEP Coal. We received approximately
$8.8 million cash and the buyer assumed an additional $11.1 million in future
reclamation liabilities. We retained an estimated $36.7 million in future
reclamation liabilities. The sale closed in April 2004 and the effect of the
sale on second quarter 2004 results of operations was not significant. The
assets and liabilities of AEP Coal have been included in Assets of Discontinued
Operations and Held for Sale and Liabilities of Discontinued Operations and Held
for Sale, respectively, in our Consolidated Balance Sheet at December 31, 2003.
DISPOSITIONS COMPLETED DURING THIRD QUARTER 2004
- ------------------------------------------------
Independent Power Producers (Investments - Other segment)
- ---------------------------------------------------------
During the third quarter of 2003, we initiated an effort to sell four domestic
Independent Power Producer (IPP) investments accounted for under the equity
method (two located in Colorado and two located in Florida). Our two Colorado
investments include a 47.75% interest in Brush II, a 68-megawatt, gas-fired,
combined cycle, cogeneration plant in Brush, Colorado and a 50% interest in
Thermo, a 272-megawatt, gas-fired, combined cycle, cogeneration plant located in
Ft. Lupton, Colorado. Our two Florida investments include a 46.25% interest in
Mulberry, a 120-megawatt, gas-fired, combined cycle, cogeneration plant located
in Bartow, Florida and a 50% interest in Orange, a 103-megawatt, gas-fired,
combined cycle, cogeneration plant located in Bartow, Florida. In accordance
with GAAP, we were required to measure the impairment of each of these four
investments individually. Based on indicative bids, it was determined that an
other than temporary impairment existed on the two equity method investments
located in Colorado. The $70.0 million pre-tax ($45.5 million, net of tax)
impairment recorded in September 2003 was the result of the measurement of fair
value that was triggered by our decision to sell these assets. This loss of
investment value was included in Investment Value Losses on our Consolidated
Statements of Operations for the periods ending September 30, 2003.
In March 2004, we entered into an agreement to sell the four domestic IPP
investments for a total sales price of $156 million, subject to closing
adjustments. An additional pre-tax impairment of $1.6 million was recorded in
June 2004 (recorded to Investment Value Losses) 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. The gain was recorded to Other
Income (Expense), Net in our Consolidated Statements of Operations in 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.
Prior to the completion of the sale of each of the four IPPs, the assets for
each of the four IPPs have been included in Investments in Power and
Distribution Projects.
U.K. Generation (Investments - UK Operations segment)
- -----------------------------------------------------
In December 2001, we acquired two coal-fired generation plants (U.K. Generation)
in the U.K. for a cash payment of $942.3 million and assumption of certain
liabilities. Subsequently and continuing through 2002, wholesale U.K. electric
power prices declined sharply as a result of domestic over-capacity and static
demand. External industry forecasts and our own projections made during the
fourth quarter of 2002 indicated that this situation may extend many years into
the future. As a result, the U.K. Generation fixed asset carrying value at
year-end 2002 was substantially impaired. A December 2002 probability-weighted
discounted cash flow analysis of the fair value of our U.K. Generation indicated
a 2002 pre-tax impairment loss of $548.7 million ($414 million after-tax). This
impairment loss is included in 2002 Discontinued Operations on our Consolidated
Statements of Operations.
In the fourth quarter of 2003, the U.K. generation plants were determined to be
non-core assets and management engaged an investment advisor to assist in
determining the best methodology to exit the U.K. business. Based on information
received, we recorded a $577 million pre-tax charge ($375 after-tax), including
asset impairments of $420.7 million during the fourth quarter of 2003 to write
down the value of the assets to their estimated realizable value. Additional
charges of $156.7 million pre-tax were also recorded in December 2003 including
$122.2 million related to the net loss on certain cash flow hedges previously
recorded in Accumulated Other Comprehensive Income (Loss) that have been
reclassified into earnings as a result of management's determination that the
hedged event is no longer probable of occurring and $34.5 million related to a
first quarter 2004 sale of certain power contracts. All write downs related to
the U.K. that were booked in the fourth quarter 2003 were included in
Discontinued Operations of our Consolidated Statements of Operations for the
year ended 2003.
In July 2004, we completed the sale of substantially all operations and assets
within the U.K. The sale included our two coal-fired generation plants
(Fiddler's Ferry and Ferrybridge) that were held-for-sale as described above,
related coal assets, and a number of related commodities contracts for
approximately $456 million. The sale resulted in a pre-tax gain of $266 million
($127 million, net of tax). As a result of the sale, the buyer assumed an
additional $46.1 million in future reclamation liabilities and $10.2 million in
pension liabilities. The remaining assets and liabilities include certain
physical 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. The assets and
liabilities of U.K. Generation have been classified as Assets of Discontinued
Operations and Held for Sale and Liabilities of Discontinued Operations and Held
for Sale, respectively, on our Consolidated Balance Sheets at September 30, 2004
and December 31, 2003. The results of operations and gain on sale are included
in Discontinued Operations on our Consolidated Statements of Operations for the
periods ending September 30, 2004 and 2003.
Texas Plants - TCC Generation Assets (Utility Operations segment)
- -----------------------------------------------------------------
In December 2002, TCC filed a plan of divestiture with the PUCT proposing to
sell all of its power generation assets, including the eight gas-fired
generating plants that were either deactivated or designated as "reliability
must run" status.
During the fourth quarter of 2003, after receiving indicative bids from
interested buyers, we recorded a $938 million impairment loss and changed the
classification of the plant assets from plant in service to Assets of
Discontinued Operations and Held for Sale. In accordance with Texas legislation,
the $938 million impairment was offset by the establishment of a regulatory
asset, which is expected to be recovered through a wires charge, subject to the
final outcome of the True-up Proceeding. As a result of the True-up Proceeding,
if we are unable to recover all or a portion of our requested costs (see Note
4), any unrecovered costs could have a material adverse effect on our results of
operations, cash flows and possibly financial condition.
In March 2004, we signed an agreement to sell eight natural gas plants, one
coal-fired plant and one hydro plant to a non-related joint venture. The sale
was completed in July 2004 for approximately $425 million, net of adjustments.
The sale did not have a significant effect on our results of operations during
the periods ended September 30, 2004.
South Coast Power Limited (Investments - Other Segment)
- -------------------------------------------------------
South Coast Power Limited (SCPL) is a 50% owned venture that was formed in 1996
to build, own and operate Shoreham Power Station, a 400-megawatt,
combined-cycle, gas turbine power station located in Shoreham, England. In 2002,
SCPL was subject to adverse wholesale electric power rates. A December 2002
projected cash flow estimate of the fair value of the investment indicated a
2002 pre-tax other than temporary impairment of the equity interest in the
amount of $63.2 million. This loss of investment value was included in
Investment Value and Other Impairment Losses in the 2002 Consolidated Statements
of Operations.
In the fourth quarter of 2003, management determined that our U.K. operations
were no longer part of our core business and as a result, a decision was made to
exit the U.K. market. In September 2004, we completed the sale of our 50%
ownership in SCPL for $46.9 million, resulting in an estimated $47.6 million net
gain ($30.9 million, net of tax) in the third quarter 2004. This gain was
recorded to Other Income (Expense), Net in our Consolidated Statements of
Operations for the periods ended September 30, 2004. The gain reflects improved
conditions in the U.K. power market.
DISPOSITIONS COMPLETED OR ANTICIPATED BEING COMPLETED DURING FOURTH QUARTER 2004
- --------------------------------------------------------------------------------
Jefferson Island Storage & Hub, L.L.C. (Investments - Gas Operations segment)
- -----------------------------------------------------------------------------
In August 2004, a definitive agreement was signed to sell the gas storage assets
of Jefferson Island Storage & Hub, L.L.C. (JISH). The sale of JISH and its
assets for $90.3 million was completed in October 2004. The sale resulted in an
additional $12.3 million pre-tax loss ($2 million, net of tax) which is
reflected in our third quarter 2004 Consolidated Statements of Operations. The
assets and liabilities of JISH are classified as Assets of Discontinued
Operations and Held for Sale and Liabilities of Discontinued Operations and Held
for Sale, respectively, on our Consolidated Balance Sheets as of September 30,
2004 and December 31, 2003. The results of operations and loss on sale of JISH
are classified as Discontinued Operations in our Consolidated Statements of
Operations for the periods ending September 30, 2004 and 2003.
Excess Real Estate (Investments - Other segment)
- ------------------------------------------------
In the fourth quarter of 2002, we began to market an under-utilized office
building in Dallas, Texas obtained through our merger with CSW in June 2000. One
prospective buyer executed an option to purchase the building. Sale of the
facility was projected by second quarter 2003 and an estimated 2002 pre-tax loss
on disposal of $15.7 million was recorded, based on the option sale price. The
estimated loss was included in Impairment Value and Other Impairment Losses in
our 2002 Consolidated Statements of Operations. We recorded an additional
pre-tax impairment of $6 million in Maintenance and Other Operation in our 2003
Consolidated Statements of Operations. The original prospective buyer did not
complete their purchase of the building by the end of 2003, and thus, the asset
no longer qualified for held for sale status. The building was then reclassified
to held and used status as of December 31, 2003.
In June 2004, we entered into negotiations to sell the Dallas office building.
This resulted in the asset again being classified as held for sale in the second
quarter of 2004. An additional pre-tax impairment of $2.5 million was recorded
in Maintenance and Other Operation expense during the second quarter of 2004 to
write down the value of the office building to the current estimated sales
price, less estimated selling expenses. In October 2004, we completed the sale
of the Dallas office building. We do not expect the sale to have a significant
effect on our results of operations. The property asset of $9.5 million at
September 30, 2004 and $12.0 million at December 31, 2003 has been classified on
our Consolidated Balance Sheets as Assets of Discontinued Operations and Held
for Sale.
DISPOSITIONS ANTICIPATED BEING COMPLETED DURING FIRST HALF 2005
- ---------------------------------------------------------------
Texas Plants - Oklaunion Power Station (Utility Operations segment)
- -------------------------------------------------------------------
In January 2004, we signed an agreement to sell TCC's 7.81% share of Oklaunion
Power Station for approximately $43 million (subject to closing adjustments) to
an unrelated party. In May 2004, we received notice from the two unaffiliated
co-owners of the Oklaunion Power Station, announcing their decision to exercise
their right of first refusal, with terms similar to the original agreement. In
June 2004 and September 2004, we entered into sales agreements with both of our
unaffiliated co-owners for the sale of TCC's 7.81% ownership of the Oklaunion
Power Station. One of these agreements is currently being challenged in Dallas
County, Texas State District Court by the unrelated party with which we entered
into the original sales agreement. The unrelated party alleges that one co-owner
has exceeded its legal authority and that the second co-owner did not exercise
its right of first refusal in a timely manner. The unrelated party has requested
that the court declare the co-owners' exercise of their rights of first refusal
void. We cannot predict when these issues will be resolved. We do not expect the
sale to have a significant effect on our future results of operations. TCC's
assets and liabilities related to the Oklaunion Power Station have been
classified as Assets of Discontinued Operations and Held for Sale and
Liabilities of Discontinued Operations and Held for Sale, respectively, in our
Consolidated Balance Sheets at September 30, 2004 and December 31, 2003.
Texas Plants - South Texas Project (Utility Operations segment)
- ---------------------------------------------------------------
In February 2004, we signed an agreement to sell TCC's 25.2% share of the STP
nuclear plant to an unrelated party for approximately $333 million, subject to
closing adjustments. In June 2004, we received notice from co-owners of their
decisions to exercise their rights of first refusal, with terms similar to the
original agreement. In September 2004, we entered into sales agreements with two
of our unaffiliated co-owners for the sale of TCC's 25.2% share of the STP
nuclear plant. We do not expect the sale to have a significant effect on our
future results of operations. We expect the sale to close in the first six
months of 2005. TCC's assets and liabilities related to STP have been classified
as Assets of Discontinued Operations and Held for Sale and Liabilities of
Discontinued Operations and Held for Sale, respectively, in our Consolidated
Balance Sheets at September 30, 2004 and December 31, 2003.
DISCONTINUED OPERATIONS
- -----------------------
Certain of our operations were determined to be discontinued operations and have
been classified as such for all periods presented. Results of operations of
these businesses have been reclassified for the three and nine month periods
ended September 30, 2004 and 2003, as shown in the following table:
For the three months ended September 30, 2004 and 2003:
Pushan
Power U.K.
Eastex Plant LIG (a) Generation Total
------ ------ ------- ---------- -----
(in millions)
2004 Revenue $- $- $1 $37 $38
2004 Pre-tax Income (Loss) - - (13) 255 242
2004 Income (Loss) After-Tax - 1 (3) 120 (b) 118
2003 Revenue 12 14 165 4 195
2003 Pre-tax Income (Loss) (1) - 2 (76) (75)
2003 Income (Loss) After-Tax - - 2 (52)(c) (50)
For the nine months ended September 30, 2004 and 2003:
Pushan
Power U.K.
Eastex Plant LIG (a) Generation Total
------ ------ ------- ---------- -----
(in millions)
2004 Revenue $- $10 $165 $112 $287
2004 Pre-tax Income (Loss) - 9 (12) 156 153
2004 Income (Loss) After-Tax - 6 (2) 56 (d) 60
2003 Revenue 58 41 518 116 733
2003 Pre-tax Income (Loss) (24) - 8 (112) (128)
2003 Income (Loss) After-Tax (15) - 6 (89)(e) (98)
(a) Includes LIG Pipeline Company and subsidiaries and Jefferson Island Storage & Hub, L.L.C.
(b) Earnings per share related to the UK Operations was $0.30
(c) Earnings per share related to the UK Operations was $(0.13)
(d) Earnings per share related to the UK Operations was $0.14
(e) Earnings per share related to the UK Operations was $(0.23)
ASSETS OF DISCONTINUED OPERATIONS AND HELD FOR SALE
- ---------------------------------------------------
The assets and liabilities of the entities that were classified as discontinued
operations or held for sale at September 30, 2004 and December 31, 2003 are as
follows:
U.K. Texas Excess Real Jefferson
September 30, 2004 Generation Plants Estate Island Total
- ------------------ ---------- ------ ------------- ------- -----
Assets: (in millions)
- -------
Current Risk Management Assets $85 $- $- $- $85
Other Current Assets 81 24 - 2 107
Property, Plant and Equipment, Net - 398 10 70 478
Regulatory Assets - 53 - - 53
Decommissioning Trusts - 134 - - 134
Goodwill - - - 14 14
Long-term Risk Management Assets 4 - - - 4
Other 5 - - 7 12
----- ----- ---- ---- -----
Total Assets of Discontinued
Operations and Held for Sale $175 $609 $10 $93 $887
===== ===== ==== ==== =====
Liabilities:
- ------------
Current Risk Management Liabilities $80 $- $- $- $80
Other Current Liabilities 61 - - 2 63
Long-term Risk Management Liabilities 11 - - - 11
Regulatory Liabilities - 1 - - 1
Asset Retirement Obligations - 231 - - 231
----- ----- ---- ---- -----
Total Liabilities of Discontinued
Operations and Held for Sale $152 $232 $- $2 $386
===== ===== ==== ==== =====
LIG
(excluding
December 31, 2003 AEP Pushan Jefferson U.K. Texas Excess Real Jefferson
- ------------------ Coal Power Plant Island) Generation Plants Estate Island Total
---- ----------- ---------- ---------- ------ ------ --------- -----
Assets: (in millions)
Current Risk Management Assets $- $- $- $560 $- $- $- $560
Other Current Assets 6 24 49 685 57 - 1 822
Property, Plant and 13 142 109 99 797 12 62 1,234
Equipment, Net
Regulatory Assets - - - - 49 - - 49
Decommissioning Trusts - - - - 125 - - 125
Goodwill - - 1 - - - 14 15
Long-term Risk Management Assets - - - 274 - - - 274
Other - - 8 6 - - 1 15
---- ----- ----- ------- ------- ---- ---- -------
Total Assets of Discontinued
Operations and Held for Sale $19 $166 $167 $1,624 $1,028 $12 $78 $3,094
==== ===== ===== ======= ======= ==== ==== =======
Liabilities:
Current Risk Management Liabilities $- $- $15 $767 $- $- $- $782
Other Current Liabilities - 26 42 221 - - 4 293
Long-term Debt - 20 - - - - - 20
Long-term Risk Managemen
Liabilities - - - 435 - - - 435
Regulatory Liabilities - - - - 9 - - 9
Asset Retirement Obligations 11 - - 29 219 - - 259
Employee Pension Obligations - - - 12 - - - 12
Deferred Credits and Other 3 57 6 - - - - 66
---- ----- ----- ------- ------- ---- ---- -------
Total Liabilities of
Discontinued Operations
and Held for Sale $14 $103 $63 $1,464 $228 $- $4 $1,876
==== ===== ===== ======= ======= ==== === =======
8. BENEFIT PLANS
-------------
Components of Net Periodic Benefit Costs
- ----------------------------------------
The following table provides the components of our net periodic benefit cost
(credit) for the following plans for the three and nine months ended September
30, 2004 and 2003:
U.S. U.S.
Pension Other Postretirement
Plans Benefit Plans
------------------- ----------------------
2004 2003 2004 2003
---- ---- ---- ----
Three Months ended September 30, 2004 and 2003: (in millions)
Service Cost $22 $20 $10 $10
Interest Cost 57 58 29 33
Expected Return on Plan Assets (73) (79) (20) (16)
Amortization of Transition
(Asset) Obligation - (2) 7 7
Amortization of Net Actuarial Loss 4 3 9 13
----- ----- ----- -----
Net Periodic Benefit Cost $10 $- $35 $47
===== ===== ===== =====
U.S. U.S.
Pension Other Postretirement
Plans Benefit Plans
------------------- ----------------------
2004 2003 2004 2003
---- ---- ---- ----
Nine Months ended September 30, 2004 and 2003: (in millions)
Service Cost $65 $60 $30 $31
Interest Cost 171 175 88 98
Expected Return on Plan Assets (219) (238) (61) (48)
Amortization of Transition
(Asset) Obligation 1 (6) 21 21
Amortization of Prior Service Cost - (1) - -
Amortization of Net Actuarial Loss 12 8 27 39
----- ----- ----- -----
Net Periodic Benefit Cost (Credit) $30 $(2) $105 $141
===== ===== ===== =====
In accordance with our implementation of FASB Staff Position FAS 106-2,
"Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003," in the second quarter 2004,
accounting for the Medicare subsidy reduced expected 2004 postretirement benefit
cost by $29 million. As a result, expected cash flows for 2004 employer
contributions to U.S. other postretirement benefit plans have been reduced by
$29 million from the $180 million disclosed at December 31, 2003. Including an
additional $19 million reduction related to refining earlier estimates, we
currently expect to contribute approximately $132 million to our U.S. other
postretirement benefit plans during 2004.
9. BUSINESS SEGMENTS
-----------------
Our segments and their related business activities are as follows:
Utility Operations
- ------------------
o Domestic generation of electricity for sale to retail and wholesale
customers
o Domestic electricity transmission and distribution
Investments - Gas Operations*
- -----------------------------
o Gas pipeline and storage services
Investments - UK Operations**
- -----------------------------
o International generation of electricity for sale to wholesale customers
o Coal procurement and transportation to our U.K. plants
Investments - Other***
- ----------------------
o Bulk commodity barging operations, windfarms, independent power producers
and other energy supply businesses
* Operations of Louisiana Intrastate Gas, including Jefferson Island
Storage, were classified as discontinued during 2003 and were sold during
the third 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.
The tables below present segment income statement information for the three and
nine months ended September 30, 2004 and 2003 and balance sheet information as
of September 30, 2004 and December 31, 2003. These amounts include certain
estimates and allocations where necessary. Prior year amounts have been
reclassified to conform to the current year's presentation.
Investments
----------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
(in millions)
Three Months Ended September 30, 2004
- -------------------------------------
Revenues from:
External Customers $2,909 $762 $- $81 $- $- $3,752
Other Operating Segments 37 (16) - 17 1 (39) -
------- ----- ----- ---- ---- ---- -------
Total Revenues 2,946 746 - 98 1 (39) 3,752
======= ===== ===== ==== ==== ==== =======
Income (Loss) Before
Discontinued Operations
and Cumulative Effect of
Accounting Changes 359 (28) - 90 (9) - 412
Discontinued Operations,
Net of Tax - (3) 120 1 - - 118
------- ----- ----- ---- ---- ---- -------
Net Income (Loss) $359 $(31) $120 $91 $(9) $- $530
======= ===== ===== ==== ==== ==== =======
As of September 30, 2004
- ------------------------
Total Assets $31,403 $2,099 $273 $1,447 $10,635 $(11,035) $34,822
Assets of Discontinued
Operations and Held for Sale 609 93 175 - 10 - 887
* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
company subsidiary, which provides services at cost to the other operating segments.
Investments
----------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
(in millions)
Three Months Ended September 30, 2003
- -------------------------------------
Revenues from:
External Customers $3,099 $707 $- $135 $- $- $3,941
Other Operating Segments 13 66 - 29 3 (111) -
------- ----- ------ ----- ----- ----- -------
Total Revenues 3,112 773 - 164 3 (111) 3,941
======= ===== ====== ===== ===== ===== =======
Income (Loss) Before
Discontinued Operations
and Cumulative Effect of
Accounting Changes 409 (21) - (45) (36) - 307
Discontinued Operations,
Net of Tax - 2 (52) - - - (50)
------- ----- ------ ----- ----- ----- -------
Net Income (Loss) $409 $(19) $(52) $(45) $(36) $- $257
======= ===== ====== ===== ===== ===== =======
As of December 31, 2003
- -----------------------
Total Assets $30,790 $2,494 $1,629 $1,714 $12,281 $(12,164) $36,744
Assets of Discontinued
Operations and Held for Sale 1,028 245 1,624 185 12 - 3,094
* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
company subsidiary, which provides services at cost to the other operating segments.
Investments
----------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
(in millions)
Nine Months Ended September 30, 2004
- ------------------------------------
Revenues from:
External Customers $7,989 $2,191 $- $281 $- $- $10,461
Other Operating Segments 106 23 - 67 5 (201) -
------- ------- ---- ----- ----- ----- --------
Total Revenues 8,095 2,214 - 348 5 (201) 10,461
======= ======= ==== ===== ===== ===== ========
Income (Loss) Before
Discontinued Operations and
Cumulative Effect of
Accounting Changes 845 (41) - 91 (43) - 852
Discontinued Operations,
Net of Tax - (2) 56 6 - - 60
------- ------- ---- ----- ----- ------ --------
Net Income (Loss) $845 $(43) $56 $97 $(43) $- $912
======= ======= ==== ===== ===== ====== ========
As of September 30, 2004
- ------------------------
Total Assets $31,403 $2,099 $273 $1,447 $10,635 $(11,035) $34,822
Assets of Discontinued
Operations and Held for Sale 609 93 175 - 10 - 887
* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
company subsidiary, which provides services at cost to the other operating segments.
Investments
----------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
(in millions)
Nine Months Ended September 30, 2003
- ------------------------------------
Revenues from:
External Customers $8,458 $2,278 $- $440 $- $- $11,176
Other Operating Segments 25 118 - 72 10 (225) -
------- ------- ------ ----- ---- ----- --------
Total Revenues 8,483 2,396 - 512 10 (225) 11,176
======= ======= ====== ===== ==== ===== ========
Income (Loss) Before
Discontinued Operations and
Cumulative Effect of
Accounting Changes 940 (64) - (45) (54) - 777
Discontinued Operations,
Net of Tax - 6 (89) (15) - - (98)
Cumulative Effect of
Accounting Changes,
Net of Tax 236 (22) (21) - - - 193
------- ------- ------ ----- ---- ---- --------
Net Income (Loss) $1,176 $(80) $(110) $(60) $(54) $- 872
======= ======= ====== ===== ==== ==== ========
As of December 31, 2003
- -----------------------
Total Assets $30,790 $2,494 $1,629 $1,714 $12,281 $(12,164) $36,744
Assets of Discontinued
Operations and Held for Sale 1,028 245 1,624 185 12 - 3,094
* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
company subsidiary, which provides services at cost to the other operating segments.
10. FINANCING ACTIVITIES
--------------------
Long-term debt and other securities issued and retired during the first nine
months of 2004 are shown in the table below.
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in millions) (%)
Issuances:
- ----------
APCo Senior Unsecured Notes $125 Variable 2007
CSPCo Installment Purchase Contracts 49 Variable 2038
CSPCo Installment Purchase Contracts 44 Variable 2038
PSO Installment Purchase Contracts 34 Variable 2014
PSO Senior Unsecured Notes 50 4.70 2009
SWEPCo Installment Purchase Contracts 54 Variable 2019
SWEPCo Installment Purchase Contracts 41 Variable 2011
Non-Registrant:
AEP Subsidiary Notes Payable 23 Variable 2009
AEP Subsidiaries Other Debt 5 Variable Various
-----
Total Issuances $425 (a)
=====
(a) Amount indicated on statement of cash flows of $416 million is net of issuance costs.
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in millions) (%)
Retirements:
- ------------
AEP Senior Unsecured Notes $57 5.25 2015
AEP Senior Unsecured Notes 10 5.375 2010
APCo First Mortgage Bonds 21 7.70 2004
APCo First Mortgage Bonds 45 7.125 2024
APCo Installment Purchase Contracts 40 5.45 2019
CSPCo First Mortgage Bonds 11 7.60 2024
CSPCo Installment Purchase Contracts 49 6.375 2020
CSPCo Installment Purchase Contracts 44 6.25 2020
I&M First Mortgage Bonds 30 7.20 2024
I&M First Mortgage Bonds 25 7.50 2024
I&M Senior Unsecured Notes 150 6.875 2004
OPCo Installment Purchase Contracts 50 6.85 2022
OPCo Notes Payable 3 6.27 2009
OPCo Notes Payable 4 6.81 2008
OPCo First Mortgage Bonds 10 7.30 2024
OPCo Senior Unsecured Notes 140 7.375 2038
OPCo Senior Unsecured Notes 100 6.75 2004
OPCo Senior Unsecured Notes 75 7.00 2004
PSO Notes Payable to Trust 77 8.00 2037
PSO Installment Purchase Contracts 1 5.90 2007
PSO Installment Purchase Contracts 34 4.875 2014
SWEPCo Installment Purchase Contracts 12 6.90 2004
SWEPCo Installment Purchase Contracts 12 6.00 2008
SWEPCo Installment Purchase Contracts 17 8.20 2011
SWEPCo Installment Purchase Contracts 54 7.60 2019
SWEPCo First Mortgage Bonds 80 6.875 2025
SWEPCo First Mortgage Bonds 40 7.75 2004
SWEPCo Notes Payable 5 4.47 2011
SWEPCo Notes Payable 2 Variable 2008
TCC Notes Payable to Trust 141 8.00 2037
TCC First Mortgage Bonds 6 6.625 2005
TCC Securitization Bonds 49 3.54 2005
TNC First Mortgage Bonds 24 6.125 2004
Non-Registrant:
AEP Subsidiaries Notes Payable 40 6.73 2004
AEP Subsidiaries Notes Payable and Other Debt 473 Variable 2007-2026
-------
Total Retirements $1,931 (b)
(b) Amount indicated on statement of cash flows of $1,898 million does not include $25 million related to retirement of debt of a
discontinued operation, $5 million related to the reacquisition of TCC's notes payable to trust and $3 million related to the
mark-to-market of risk management contracts.
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in millions) (%)
Defeasance:
- -----------
TCC First Mortgage Bonds $27 7.25 2004
TCC First Mortgage Bonds 66 6.625 2005
TCC First Mortgage Bonds 19 7.125 2008
-----
Total Defeased $112 (c)
=====
(c) Trust fund assets for defeasance of First Mortgage Bonds of $100 million are included in Other Cash Deposits and $22 million
are included in Other Non-current Assets in the Consolidated Balance Sheets at September 30, 2004. Trust fund assets are
restricted for exclusive use in funding the interest and principal due on the First Mortgage Bonds.
AEP GENERATING COMPANY
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Operating revenues are derived from the sale of our share of Rockport Plant
energy and capacity to I&M and KPCo pursuant to FERC approved long-term unit
power agreements. The unit power agreements provide for a FERC approved rate of
return on common equity, a return on other capital (net of temporary cash
investments) and recovery of costs including operation and maintenance, fuel and
taxes.
Net Income increased $383 thousand for the third quarter of 2004 compared with
the third quarter of 2003 and increased $152 thousand for the nine months ended
September 30, 2004 compared with the nine months ended September 30, 2003. The
fluctuations in Net Income are a result of terms in the unit power agreements
which allow for the return on total capital of the Rockport Plant calculated and
adjusted monthly.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income increased $405 thousand for the third quarter of 2004 compared
with the third quarter of 2003. The largest variances related to:
o A $6 million increase in Operating Revenues as a result of increased
recoverable fuel expenses in accordance with the unit power agreements.
o A $5 million increase in Fuel for Electric Generation expenses.
This increase is primarily due to fewer outages during third quarter 2004
resulting in a 5% higher MWH output combined with increasing fuel prices.
o A $1 million increase in Taxes Other Than Income Taxes as a result of State
of Indiana property tax re-appraisals.
o A $1 million decrease in Maintenance expenses as a result of decreased
outages compared to the prior year period.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were (2.7)% and
(10.7)% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is primarily due to amortization of investment tax
credits, flow-through of book versus tax temporary differences, and state income
taxes. The increase in the effective tax rate is primarily due to higher pre-tax
income in 2004.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income was down slightly over the prior year period. The largest
variances related to:
o An $8 million decrease in Fuel for Electric Generation expenses. This
decrease is primarily due to a 14% decrease in MWH generation as a result
of both planned and forced outages.
o A $4 million increase in Maintenance expenses as a result of increased
planned boiler inspections and forced repairs.
o A $2 million decrease in Operating Revenues as a result of decreased
recoverable expenses in accordance with the unit power agreements.
o A $1 million increase in Taxes Other Than Income Taxes as a result of
State of Indiana property tax re-appraisals.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were (8.9)%
and (14.1)% respectively. The difference in the effective income tax rate and
the federal statutory rate of 35% is primarily due to amortization of investment
tax credits, flow-through of book versus tax temporary differences, and state
income taxes. The increase in the effective tax rate is primarily due to higher
pre-tax income in 2004.
Off-balance Sheet Arrangements
- ------------------------------
In prior years, we entered into off-balance sheet arrangements. Our current
policy restricts the use of off-balance sheet financing entities or structures,
except for traditional operating lease arrangements. Our off-balance sheet
arrangement has not changed significantly from year-end 2003 and is comprised of
a sale and leaseback transaction entered into by AEGCo and I&M with an unrelated
unconsolidated trustee. For complete information on this off-balance sheet
arrangement see "Off-balance Sheet Arrangements" in "Management's Narrative
Financial Discussion and Analysis" section of our 2003 Annual Report.
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets and the impact of new accounting pronouncements.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
------------------------ -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $65,303 $59,008 $176,933 $179,004
-------- -------- --------- ---------
OPERATING EXPENSES
- ---------------------------------------
Fuel for Electric Generation 32,857 27,514 79,291 87,148
Rent - Rockport Plant Unit 2 17,071 17,071 51,212 51,212
Other Operation 2,472 2,691 7,628 7,683
Maintenance 1,835 2,461 10,025 6,399
Depreciation and Amortization 5,941 5,695 17,447 16,981
Taxes Other Than Income Taxes 2,070 1,085 3,956 2,480
Income Taxes 843 682 2,240 1,927
-------- -------- --------- ---------
TOTAL 63,089 57,199 171,799 173,830
-------- -------- --------- ---------
OPERATING INCOME 2,214 1,809 5,134 5,174
Nonoperating Income - 3 43 24
Nonoperating Expenses 72 44 235 286
Nonoperating Income Tax Credits 905 878 2,709 2,617
Interest Charges 643 625 1,914 1,944
-------- -------- --------- ---------
NET INCOME $2,404 $2,021 $5,737 $5,585
======== ======== ========= =========
STATEMENTS OF RETAINED EARNINGS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
------------------------ -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $22,251 $19,384 $21,441 $18,163
Net Income 2,404 2,021 5,737 5,585
Cash Dividends Declared 1,262 1,172 3,785 3,515
-------- -------- -------- --------
BALANCE AT END OF PERIOD $23,393 $20,233 $23,393 $20,233
======== ======== ======== ========
The common stock of AEGCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
AEP GENERATING COMPANY
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- --------------------------------------------------
Production $668,336 $645,251
General 3,826 4,063
Construction Work in Progress 5,348 24,741
--------- ---------
TOTAL 677,510 674,055
Accumulated Depreciation 363,050 351,062
--------- ---------
TOTAL - NET 314,460 322,993
--------- ---------
OTHER PROPERTY AND INVESTMENTS
- --------------------------------------------------
Non-Utility Property, Net 119 119
--------- ---------
CURRENT ASSETS
- --------------------------------------------------
Accounts Receivable - Affiliated Companies 22,161 24,748
Fuel 18,837 20,139
Materials and Supplies 5,774 5,419
Prepayments 11 -
--------- ---------
TOTAL 46,783 50,306
--------- ---------
DEFERRED DEBITS AND OTHER ASSETS
- --------------------------------------------------
Regulatory Assets:
Unamortized Loss on Reacquired Debt 4,555 4,733
Asset Retirement Obligations 1,069 928
Deferred Property Taxes 1,344 502
Other Deferred Charges 429 464
--------- ---------
TOTAL 7,397 6,627
--------- ---------
TOTAL ASSETS $368,759 $380,045
========= =========
See Notes to Financial Statements of Registrant Subsidiaries.
AEP GENERATING COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - Par Value $1,000 per share:
Authorized and Outstanding - 1,000 Shares $1,000 $1,000
Paid-in Capital 23,434 23,434
Retained Earnings 23,393 21,441
--------- ---------
Total Common Shareholder's Equity 47,827 45,875
Long-term Debt 44,818 44,811
--------- ---------
TOTAL 92,645 90,686
--------- ---------
CURRENT LIABILITIES
- ------------------------------------------------------------
Advances from Affiliates 15,497 36,892
Accounts Payable:
General 543 498
Affiliated Companies 12,991 15,911
Taxes Accrued 10,039 6,070
Interest Accrued 456 911
Obligations Under Capital Leases 62 87
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Other 108 -
--------- ---------
TOTAL 63,123 65,332
--------- ---------
DEFERRED CREDITS AND OTHER LIABILITIES
- ------------------------------------------------------------
Deferred Income Taxes 23,843 24,329
Regulatory Liabilities:
Asset Removal Costs 25,414 27,822
Deferred Investment Tax Credits 47,087 49,589
SFAS 109 Regulatory Liability, Net 14,003 15,505
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 101,297 105,475
Obligations Under Capital Leases 154 182
Asset Retirement Obligations 1,193 1,125
--------- ---------
TOTAL 212,991 224,027
--------- ---------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $368,759 $380,045
========= =========
See Notes to Financial Statements of Registrant Subsidiaries.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------------
Net Income $5,737 $5,585
Adjustments to Reconcile Net Income to Net Cash Flows From
Operating Activities:
Depreciation and Amortization 17,447 16,981
Deferred Income Taxes (1,987) (3,268)
Deferred Investment Tax Credits (2,502) (2,503)
Deferred Property Taxes (842) (795)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (4,178) (4,178)
Changes in Certain Assets and Liabilities:
Accounts Receivable 2,587 (2,027)
Fuel, Materials and Supplies 947 5,165
Accounts Payable, Net (2,875) (1,757)
Taxes Accrued 3,969 2,033
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets 2,395 1,383
Change in Other Liabilities (2,734) (558)
-------- --------
Net Cash Flows From Operating Activities 36,428 34,525
-------- --------
INVESTING ACTIVITIES
- ------------------------------------------------------------
Construction Expenditures (11,248) (9,855)
-------- --------
Net Cash Flows Used For Investing Activities (11,248) (9,855)
-------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------------
Change in Advances from Affiliates (21,395) (21,155)
Dividends Paid (3,785) (3,515)
-------- --------
Net Cash Flows Used For Financing Activities (25,180) (24,670)
-------- --------
Net Decrease in Cash and Cash Equivalents - -
Cash and Cash Equivalents at Beginning of Period - -
-------- --------
Cash and Cash Equivalents at End of Period $- $-
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $2,170,000 and $2,200,000 and for income taxes was $87,000 and $5,939,000
in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries.
AEP GENERATING COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to AEGCo's financial statements are combined with the notes to
financial statements for other subsidiary registrants. Listed below are the
notes that apply to AEGCo.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Commitments and Contingencies Note 5
Guarantees Note 6
Business Segments Note 9
Financing Activities Note 10
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income decreased $122 million for 2004 year-to-date and $23 million for the
third quarter. The three major factors driving the year-to-date decline are
decreased revenues associated with establishing regulatory assets in Texas and
the provision for refunds of fuel charges, offset in part by the cessation of
deprecation on plants held for sale. The major factors driving the decline for
the quarter are decreased revenues associated with establishing regulatory
assets in Texas offset in part by the cessation of deprecation on plants held
for sale and increased delivery revenues. The sale of several of our generation
plants in July 2004 affected numerous line items on the income statement.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income for the three months ended September 30, 2004 decreased $17
million from the prior year period primarily due to:
o A $61 million decrease in revenues associated with establishing regulatory
assets in Texas in 2003 (see "Texas Restructuring" in Note 4). These
revenues did not continue after 2003.
o A $60 million decrease in Reliability Must Run (RMR) revenues from ERCOT.
This amount includes both a fixed cost component decrease of $7 million and
a fuel recovery decrease of $53 million primarily due to the sale of
certain generation plants.
o A $22 million decrease in system sales, including those to Retail Electric
Providers (REP), primarily due to lower KWH sales of 32%. The lower KWH
sales are due to customer choice in Texas and the sale of certain
generation plants.
o A $3 million decrease in margins resulting from risk management activities.
o A $3 million increase in Other Operation expenses primarily due to a $5
million increase of ERCOT-related transmission expenses and affiliated
ancillary services and $3 million in customer-related expenses. These
increases were partially offset by decreased production expenses primarily
due to the sale of certain generation plants.
The decrease in Operating Income for the third quarter of 2004 was partially
offset by:
o A $91 million net decrease in fuel and purchased power expenses. KWHs
purchased decreased 9% while the per unit cost increased 18%. Although
the KWHs generated decreased 57%, generating costs decreased 91%
attributable mostly to the sale of certain generation units.
o A $13 million decrease in Depreciation and Amortization expenses primarily
due to the cessation of depreciation on plants classified as held for sale
(see Note 7 "Dispositions and Assets Held for Sale").
o A $9 million increase in retail delivery revenues primarily driven by an
increase in cooling degree-days of 5%.
o A $7 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
o A $4 million decrease in Maintenance expenses primarily due to the sale of
certain generation plants.
o A $3 million increase in other electric revenue primarily due to
Qualified Scheduling Entity (QSE) fees, rent from electric property and
miscellaneous service revenue.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $18 million primarily as a result of risk
management activities.
Interest Charges decreased $4 million primarily due to the defeasance of $112
million of First Mortgage Bonds, the deferral of the interest cost as a
regulatory asset related to the cost of the sale of certain generation assets,
redemption of the 8% Notes Payable to Trust and other financing activities.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 28.0% and
32.0% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower pre-tax income in 2004 and consolidated tax
savings from parent.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income for the nine months ended September 30, 2004 decreased $126
million from the prior year period primarily due to:
o A $188 million decrease in system sales, including those to REPs, primarily
due to lower KWH sales of 33%. The decrease in KWH sales is due to customer
choice in Texas and the sale of certain generation plants. There was also
a small decrease in the overall average price per KWH.
o A $169 million decrease in revenues associated with establishing regulatory
assets in Texas in 2003 (see "Texas Restructuring" in Note 4).
o A $69 million decrease in RMR revenues from ERCOT which includes both a
fuel recovery decrease of $61 million and a fixed cost component decrease
of $8 million.
o A $22 million increase in provisions for rate refunds due to fuel
reconciliation issues (see "TCC Fuel Reconciliation" in Note 3).
o A $20 million increase in Other Operation expenses primarily due to
$13 million increase of ERCOT-related transmission expense and affiliated
ancillary services; $1 million increase in production expenses including
emission allowances; $3 million increase in customer related expenses; and
a $3 million increase in administrative and support expenses.
o An $18 million decrease in margins from risk management activities.
o A $13 million decrease in retail delivery revenues driven by a decrease in
KWH of 1% due in large part to a decrease in heating and cooling degree-days
of 7%.
o A $6 million decrease in QSE fees primarily due to one REP not using TCC as
their QSE in 2004.
o A $3 million decrease in revenues from ERCOT for various services including
balancing energy.
o A $2 million increase in Taxes Other Than Income Taxes primarily due to an
increase of $3 million related to property taxes attributable to changes
in property values, property tax rates, net fixed asset decreases - which
includes the sale of certain generation plants, accrual update adjustments
and timing of prior period adjustments offset in part by lower franchise
taxes of $1 million.
The decrease in Operating Income was partially offset by:
o A $254 million net decrease in fuel and purchased power expenses. KWHs
purchased decreased 59% while the per unit cost increased 17%. Per unit
generation costs decreased 25% and KWHs generated decreased 11% due to the
sale of certain generation plants.
o A $68 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
o A $55 million decrease in Depreciation and Amortization expenses primarily
due to the cessation of depreciation on plants classified as held for sale
(see Note 7 "Dispositions and Assets Held for Sale").
o A $13 million increase in transmission revenue primarily due to
affiliated OATT (including a $7.6 million true-up for prior years
recorded in 2004) and ancillary services.
o A $3 million decrease in Maintenance expenses primarily due to the sale of
certain generation plants.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $12 million primarily as a result of risk
management activities of $9 million and $6 million in lower non-utility revenues
associated with energy-related construction projects for third parties offset in
part by a $2 million increase attributed to higher allowance for funds used
during construction and interest income.
Nonoperating Expenses decreased $3 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties.
Interest Charges decreased $6 million primarily due to the defeasance of $112
million of First Mortgage Bonds, the deferral of the interest cost as a
regulatory asset related to the cost of the sale of generation assets, the
redemption of the 8% Notes Payable to Trust and other financing activities.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were 24.3%
and 33.6% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower pre-tax income in 2004 and consolidated tax
savings from parent.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Our current ratings are
as follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds Baa1 BBB A
Senior Unsecured Debt Baa2 BBB A-
Cash Flow
- ---------
Cash flows for the nine months ended September 30, 2004 and 2003 were as
follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $760 $808
--------- ---------
Cash flow from (used for):
Operating activities 193,107 239,370
Investing activities 258,422 (49,653)
Financing activities (450,529) (187,220)
--------- ---------
Net increase in cash and cash equivalents 1,000 2,497
--------- ---------
Cash and cash equivalents at end of period $1,760 $3,305
========= =========
Operating Activities
- --------------------
Our cash flows from operating activities were $193 million for the first nine
months of 2004. We produced income of $72 million during the period including
noncash expense items of $93 million for depreciation, amortization and $(121)
million for deferred income taxes. 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 taxes accrued of
$147 million and a decrease in interest accrued of $20 million.
Investing Activities
- --------------------
Cash Flows From Investing Activities were $258 million in 2004 primarily due to
proceeds from the sale of several of our generation plants offset in part by $72
million in construction expenditures and $118 million in cash deposits for
future long-term debt retirement. For the remainder of 2004, we expect our
Construction Expenditures to be approximately $63 million.
Financing Activities
- --------------------
Cash Flows Used for Financing Activities of $451 million in 2004 were due to
retirements of long-term debt, payment of dividends and increased Advances to
Affiliates.
Financing Activity
- ------------------
Long-term debt issuances, retirements and defeasance during the first nine
months of 2004 were:
Issuances
- ---------
None
Retirements
- -----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $ 6,195 6.625 2005
Securitization Bonds 48,551 3.540 2005
Notes Payable to Trust 140,889 8.00 2037
Defeasance
- ----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $27,400 7.25 2004
First Mortgage Bonds 65,763 6.625 2005
First Mortgage Bonds 18,581 7.125 2008
Liquidity
- ---------
We have solid investment grade ratings which provide us ready access to capital
markets in order to refinance long-term debt maturities. In addition, we
participate in the AEP Utility Money Pool, which provides access to the
liquidity of the AEP System. Finally, we expect to receive asset sale proceeds
of approximately $376 million in the first half of 2005. These proceeds may be
used to reduce current portions of long-term debt outstanding.
Significant Factors
- -------------------
We made progress on our planned divestiture of all of our generation assets by
(1) announcing in June 2004 and September 2004 that we had signed agreements to
sell our 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 our 25.2% share of the South Texas Project 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 our remaining
generation assets, including eight natural gas plants, one coal-fired plant and
one hydro plant for approximately $425 million, net of adjustments. We expect
the sales of Oklaunion and South Texas Project 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. We will
file with the Public Utility Commission of Texas 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.
Nuclear Decommissioning
- -----------------------
As discussed in the 2003 Annual Report, decommissioning costs are accrued over
the service life of STP. The licenses to operate the two nuclear units at STP
expire in 2027 and 2028. TCC had estimated its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of approximately $8 million per year.
In May 2004, an updated decommissioning study was completed for STP. The study
estimates TCC's share of the decommissioning costs of STP to be $344 million in
nondiscounted 2004 dollars. We are currently analyzing the STP study to
determine the effect on our asset retirement obligations (ARO) and will make any
appropriate adjustments to the ARO liability and related regulatory asset in the
fourth quarter 2004. As discussed in Note 7, TCC is in the process of selling
its ownership interest in STP to a non-affiliate, and upon completion of the
sale it is anticipated that TCC will no longer be obligated for nuclear
decommissioning liabilities associated with STP.
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.
MTM Risk Management Contract Net Liabilities
- --------------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Liabilities
Nine Months Ended September 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $11,942
(Gain) Loss from Contracts Realized/Settled During the Period (a) (4,555)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) (98)
Change in Fair Value Due to Valuation Methodology Changes (d) 110
Changes in Fair Value of Risk Management Contracts (e) 552
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f) -
--------
Total MTM Risk Management Contract Net Assets 7,951
Net Cash Flow Hedge Contracts (g) (10,832)
--------
Total MTM Risk Management Contract Net Liabilities at September 30, 2004 $(2,881)
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long- term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and
unexpired option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changing methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
etc.
(f) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Statements of Income. These
net gains (losses) are recorded as regulatory liabilities/assets
for those subsidiaries that operate in regulated jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of September 30, 2004
MTM Risk
Management Cash Flow
Contracts (a) Hedges Consolidated (b)
------------- --------- ----------------
(in thousands)
Current Assets $17,277 $193 $17,470
Non Current Assets 8,373 59 8,432
-------- --------- --------
Total MTM Derivative
Contract Assets 25,650 252 25,902
-------- --------- --------
Current Liabilities (13,774) (10,684) (24,458)
Non Current Liabilities (3,925) (400) (4,325)
-------- --------- --------
Total MTM Derivative
Contract Liabilities (17,699) (11,084) (28,783)
-------- --------- --------
Total MTM Derivative Contract
Net Assets (Liabilities) $7,951 $(10,832) $(2,881)
======== ========= ========
(a) Does not include Cash Flow Hedges.
(b) Represents amount of total MTM derivative contracts recorded
within Risk Management Assets, Long-term Risk Management Assets,
Risk Management Liabilities and Long-term Risk Management
Liabilities on our Consolidated Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 (c) Total (d)
--------- ---- ---- ---- ---- -------- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $618 $(1,849) $8 $585 $- $- $(638)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (2,381) 4,313 385 - - - 2,317
Prices Based on Models and Other
Valuation Methods (b) 2,496 891 186 (49) 672 2,076 6,272
------- -------- ----- ----- ----- ------- -------
Total $733 $3,355 $579 $536 $672 $2,076 $7,951
======= ======== ===== ===== ===== ======= =======
(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over-the- counter brokers, industry services,
or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources. Modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(c) There is mark-to-market value in excess of 10 percent of our total
mark-to-market value in individual periods beyond 2008, of which $813
thousand of this mark-to-market value is in 2009.
(d) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $(1,828)
Changes in Fair Value (a) (6,134)
Reclassifications from AOCI to Net
Income (b) 1,004
--------
Ending Balance September 30, 2004 $(6,958)
========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $6,736 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Management Contracts
- ----------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
--------------------------- ---------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$86 $479 $223 $78 $189 $733 $307 $73
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates primarily related to long-term debt with fixed interest rates was
$131 million and $206 million at September 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
---------------------- --------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ----------------------------------------------------
Electric Generation, Transmission and Distribution $347,013 $443,578 $872,835 $1,264,757
Sales to AEP Affiliates 7,596 41,551 38,622 131,176
--------- --------- --------- -----------
TOTAL 354,609 485,129 911,457 1,395,933
--------- --------- --------- -----------
OPERATING EXPENSES
- ----------------------------------------------------
Fuel for Electric Generation 6,967 24,475 50,879 73,244
Fuel from Affiliates for Electric Generation 1,707 72,776 101,883 155,976
Purchased Electricity for Resale 114,371 116,562 140,925 305,338
Purchased Electricity from AEP Affiliates 54 273 6,065 19,045
Other Operation 74,780 72,185 228,198 207,863
Maintenance 12,215 16,657 51,328 54,567
Depreciation and Amortization 34,884 48,158 92,860 148,105
Taxes Other Than Income Taxes 23,814 24,747 69,028 67,509
Income Taxes 18,027 24,794 23,645 91,171
--------- --------- --------- -----------
TOTAL 286,819 400,627 764,811 1,122,818
--------- --------- --------- -----------
OPERATING INCOME 67,790 84,502 146,646 273,115
Nonoperating Income 6,783 25,006 30,946 43,069
Nonoperating Expenses 3,628 3,647 11,384 14,479
Nonoperating Income Tax Expense (Credit) (1,336) 6,319 (476) 7,117
Interest Charges 29,269 33,321 94,609 100,343
--------- --------- --------- -----------
Income Before Cumulative Effect of Accounting Change 43,012 66,221 72,075 194,245
Cumulative Effect of Accounting Change (Net of Tax) - - - 122
--------- --------- --------- -----------
NET INCOME 43,012 66,221 72,075 194,367
Preferred Stock Dividend Requirements 60 60 181 181
--------- --------- --------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $42,952 $66,161 $71,894 $194,186
========= ========= ========= ===========
The common stock of TCC is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $55,292 $132,606 $986,396 $(73,160) $1,101,134
Common Stock Dividends (90,601) (90,601)
Preferred Stock Dividends (181) (181)
-----------
TOTAL 1,010,352
-----------
COMPREHENSIVE INCOME
- --------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges 337 337
NET INCOME 194,367 194,367
-----------
TOTAL COMPREHENSIVE INCOME 194,704
-------- --------- ----------- --------- -----------
SEPTEMBER 30, 2003 $55,292 $132,606 $1,089,981 $(72,823) $1,205,056
======== ========= =========== ========= ===========
DECEMBER 31, 2003 $55,292 $132,606 $1,083,023 $(61,872) $1,209,049
Common Stock Dividends (148,000) (148,000)
Preferred Stock Dividends (181) (181)
-----------
TOTAL 1,060,868
-----------
COMPREHENSIVE INCOME
- --------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (5,130) (5,130)
Minimum Pension Liability (3,471) (3,471)
NET INCOME 72,075 72,075
-----------
TOTAL COMPREHENSIVE INCOME 63,474
-------- --------- ----------- --------- -----------
SEPTEMBER 30, 2004 $55,292 $132,606 $1,006,917 $(70,473) $1,124,342
======== ========= =========== ========= ===========
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ----------------------------------------------
Production $- $-
Transmission 782,006 767,970
Distribution 1,420,683 1,376,761
General 231,533 221,354
Construction Work in Progress 42,098 58,953
----------- -----------
TOTAL 2,476,320 2,425,038
Accumulated Depreciation and Amortization
724,408 695,359
----------- -----------
TOTAL - NET
1,751,912 1,729,679
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ----------------------------------------------
Non-Utility Property, Net 1,584 1,302
Bond Defeasance Funds 21,945 -
Other Investments - 4,639
----------- -----------
TOTAL 23,529 5,941
----------- -----------
CURRENT ASSETS
- ----------------------------------------------
Cash and Cash Equivalents 1,760 760
Other Cash Deposits 139,254 65,122
Advances to Affiliates 172,051 60,699
Accounts Receivable:
Customers 140,184 146,630
Affiliated Companies 74,742 78,484
Accrued Unbilled Revenues 24,457 23,077
Allowance for Uncollectible Accounts (3,406) (1,710)
Materials and Supplies 12,557 11,708
Risk Management Assets 17,470 22,051
Margin Deposits 1,142 3,230
Prepayments and Other Current Assets 5,176 6,770
----------- -----------
TOTAL 585,387 416,821
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ----------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 3,516 3,249
Wholesale Capacity Auction True-up 480,000 480,000
Unamortized Loss on Reacquired Debt 12,108 9,086
Designated for Securitization 1,273,912 1,259,714
Deferred Debt - Restructuring 11,952 12,015
Other 108,877 127,488
Securitized Transition Assets 656,556 689,399
Long-term Risk Management Assets 8,432 7,627
Deferred Charges 57,978 55,554
----------- -----------
TOTAL 2,613,331 2,644,132
----------- -----------
Assets Held for Sale - Texas Generation Plants 608,759 1,028,134
----------- -----------
TOTAL ASSETS $5,582,918 $5,824,707
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ----------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 2,211,678 Shares $55,292 $55,292
Paid-in Capital 132,606 132,606
Retained Earnings 1,006,917 1,083,023
Accumulated Other Comprehensive Income (Loss) (70,473) (61,872)
----------- -----------
Total Common Shareholder's Equity 1,124,342 1,209,049
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,940 5,940
----------- -----------
Total Shareholders' Equity 1,130,282 1,214,989
Long-term Debt 1,541,450 2,053,974
----------- -----------
TOTAL 2,671,732 3,268,963
----------- -----------
CURRENT LIABILITIES
- ----------------------------------------------------------------
Long-term Debt Due Within One Year 554,842 237,651
Accounts Payable:
General 95,179 90,004
Affiliated Companies 62,686 74,209
Customer Deposits 6,289 1,517
Taxes Accrued 214,269 67,018
Interest Accrued 23,161 43,196
Risk Management Liabilities 24,458 17,888
Obligation Under Capital Leases 417 407
Other 17,254 23,248
----------- -----------
TOTAL 998,555 555,138
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ----------------------------------------------------------------
Deferred Income Taxes 1,126,802 1,244,912
Long-term Risk Management Liabilities 4,325 2,660
Regulatory Liabilities:
Asset Removal Costs 102,996 95,415
Deferred Investment Tax Credits 108,809 112,479
Over Recovery of Fuel Costs 69,026 69,026
Retail Clawback 29,824 45,527
Other 41,196 56,984
Obligation Under Capital Leases 497 636
Deferred Credits and Other 196,857 144,833
----------- -----------
TOTAL 1,680,332 1,772,472
----------- -----------
Liabilities Held for Sale - Texas Generation Plants 232,299 228,134
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $5,582,918 $5,824,707
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- --------------------------------------------------------
Net Income $72,075 $194,367
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change - (122)
Depreciation and Amortization 92,860 148,105
Deferred Income Taxes (121,111) 36,386
Deferred Investment Tax Credits (3,670) (3,905)
Deferred Property Taxes (5,996) (10,050)
Mark-to-Market of Risk Management Contracts 3,991 (13,426)
Wholesale Capacity Auction True-up - (169,000)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 10,504 (52,502)
Fuel, Materials and Supplies (7,494) 17,060
Accounts Payable, Net (6,348) 71,815
Taxes Accrued 147,251 24,043
Interest Accrued (20,035) (26,738)
Change in Other Assets (2,572) 13,562
Change in Other Liabilities 33,652 9,775
--------- ---------
Net Cash Flows From Operating Activities 193,107 239,370
--------- ---------
INVESTING ACTIVITIES
- --------------------------------------------------------
Construction Expenditures (72,341) (95,425)
Proceeds from Sale of Property and Other Assets 426,566 -
Change in Other Cash Deposits, Net (74,132) 45,165
Change in Bond Defeasance Funds and Other (21,671) 607
--------- ---------
Net Cash Flows From (Used For) Investing Activities 258,422 (49,653)
--------- ---------
FINANCING ACTIVITIES
- --------------------------------------------------------
Change in Short-term Debt - Affiliates - (650,000)
Issuance of Long-term Debt - 792,027
Retirement of Long-term Debt (190,996) (85,427)
Change in Advances to Affiliates (111,352) (153,038)
Dividends Paid on Common Stock (148,000) (90,601)
Dividends Paid on Cumulative Preferred Stock (181) (181)
--------- ---------
Net Cash Flows Used For Financing Activities (450,529) (187,220)
--------- ---------
Net Increase in Cash and Cash Equivalents 1,000 2,497
Cash and Cash Equivalents at Beginning of Period 760 808
--------- ---------
Cash and Cash Equivalents at End of Period $1,760 $3,305
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $108,791,000 and $117,427,000 and for income taxes was
$(1,058,000) and $42,901,000 in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to TCC's consolidated financial statements are combined with the notes
to financial statements for other subsidiary registrants. Listed below are the
notes that apply to TCC.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Dispositions and Assets Held for Sale Note 7
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
AEP TEXAS NORTH COMPANY
AEP TEXAS NORTH COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Net Income decreased $7 million for 2004 year-to-date and $0.5 million for the
third quarter. The year-to-date decrease was primarily driven by lower margins
from risk management activities and a 2003 Cumulative Effect of Accounting
Changes.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income for the three months ended September 30, 2004 increased $4
million from the prior year period primarily due to:
o A $30 million increase in system sales, including those to Retail Electric
Providers (REP), primarily due to higher KWH sales of 53%.
o A $5 million increase in revenues from ERCOT for various services,
including balancing energy and prior year's adjustments made by ERCOT
recorded in 2003 and 2004.
o A $2 million increase in margins from risk management activities.
o A $2 million increase in transmission revenue primarily due to affiliated
ancillary services.
The increase in Operating Income was partially offset by:
o A $29 million net increase in fuel and purchased power expenses. KWH
generation decreased 6% while the generation cost per KWH increased 20%
primarily due to increases in the price of natural gas. KWH's purchased
increased 137% and the average cost per KWH purchased increased 6%.
o A $2 million increase in Depreciation and Amortization expenses resulting
mainly from the prior year adjustment to the excess earnings accruals
related to Texas Legislation (see "Texas Restructuring" in Note 4).
o A $1 million decrease in Reliability Must Run (RMR) revenues from ERCOT
which includes a fuel recovery component and a fixed cost component.
o A $1 million increase in Taxes Other Than Income Taxes primarily due to
higher accrued property taxes attributable to changes in property values,
property tax rates, net fixed asset increases, accrual update adjustments
and timing of prior period adjustments.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $15 million as a result of a $9 million decrease
in non-utility revenues associated with energy-related construction projects for
third parties and a $6 million decrease related to risk management activities.
Nonoperating Expenses decreased $7 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 33.1% and
36.8% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower state income taxes and federal income tax return
adjustments.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income for the nine months ended September 30, 2004 decreased $1
million from the prior year period primarily due to:
o A $14 million decrease in system sales, including those to REPs,
primarily due to both lower KWH sales of 2% due to customer choice in
Texas and a small decrease in the overall average price per KWH.
o A $7 million decrease in margins from risk management activities.
o A $5 million decrease in other electric revenue primarily due to Qualified
Scheduling Entity fees and miscellaneous service revenue.
o A $3 million increase in Depreciation and Amortization expenses primarily
due to the prior year adjustment for excess earnings accruals related to
the Texas Legislation (see "Texas Restructuring" in Note 4).
o A $2 million decrease in retail delivery revenues due partly to a 16%
decline in heating and cooling degree-days.
o A $2 million increase in Taxes Other Than Income Taxes primarily due to
higher accrued property taxes attributable to changes in property values,
property tax rates, net fixed asset increases, accrual update adjustments
and timing of prior period adjustments.
o A $1 million increase in provision for rate refunds due to fuel
reconciliation issues in 2003 (see "TNC Fuel Reconciliation" in Note 3).
The decrease in Operating Income was partially offset by:
o A $7 million net decrease in fuel and purchased power expenses. KWH's
purchased increased 7% while the average cost per KWH purchased decreased
25%. KWH generation increased 1% while the generation cost per KWH
increased 12% primarily due to increases in the price of natural gas.
o A $10 million increase in transmission revenue primarily due to prior year
adjustments recorded in 2004 for affiliated OATT and ancillary services
resulting from revised data received from ERCOT for the years 2001-2003.
o A $5 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
o A $4 million increase in revenues from ERCOT for various services,
including balancing energy and prior year adjustments made by ERCOT and
recorded in 2003 and 2004.
o A $3 million increase in RMR revenues from ERCOT which include a fuel
recovery increase of $6 million and a fixed cost decrease of $3 million.
o A $3 million decrease in Other Operation expenses primarily due to
proceeds of $1 million for the sale of emission allowances; decreased
production expenses of approximately $1 million due to the elimination of
the RMR status for the San Angelo Power Station - Unit 1; decreased
transmission related expenses of $2 million offset in part by increased
employee-related expenses.
o A $1 million increase in wholesale revenues due to higher fuel revenue
which is part of average fuel cost pricing.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $17 million primarily as a result of a $14 million
decrease in non-utility revenue associated with energy-related construction
projects for third parties and a decrease of $3 million related to risk
management activities.
Nonoperating Expenses decreased $13 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties.
The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143, "Accounting for Asset Retirement Obligations,"
(SFAS 143) effective January 1, 2003.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were 33.4%
and 37.0% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower state income taxes and federal income tax return
adjustments.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Our current ratings are
as follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 BBB A
Senior Unsecured Debt Baa1 BBB A-
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first nine months of 2004
were:
Issuances
---------
None.
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $24,036 6.125 2004
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effects.
MTM Risk Management Contract Net Liabilities
- --------------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Liabilities
Nine Months Ended September 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $4,620
(Gain) Loss from Contracts Realized/Settled During the Period (a) (1,728)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) (43)
Change in Fair Value Due to Valuation Methodology Changes (d) 45
Changes in Fair Value of Risk Management Contracts (e) 408
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f) -
-------
Total MTM Risk Management Contract Net Assets 3,302
Net Cash Flow Hedge Contracts (g) (3,770)
-------
Total MTM Risk Management Contract Net Liabilities at September 30, 2004 $(468)
=======
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and
unexpired option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changing methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
etc.
(f) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Statements of Income. These
net gains (losses) are recorded as regulatory liabilities/assets
for those subsidiaries that operate in regulated jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
Reconciliation of MTM Risk Management Contracts to
Balance Sheets
As of September 30, 2004
MTM Risk
Management Cash Flow
Contracts (a) Hedges Total (b)
------------- --------- ---------
(in thousands)
Current Assets $7,221 $83 $7,304
Non Current Assets 3,619 25 3,644
------- -------- --------
Total MTM Derivative
Contract Assets 10,840 108 10,948
------- -------- --------
Current Liabilities (5,842) (3,705) (9,547)
Non Current Liabilities (1,696) (173) (1,869)
------- -------- --------
Total MTM Derivative
Contract Liabilities (7,538) (3,878) (11,416)
------- -------- --------
Total MTM Derivative
Contract Net Assets
(Liabilities) $3,302 $(3,770) $(468)
======= ======== ========
(a) Does not include Cash Flow Hedges.
(b) Represents amount of total MTM derivative contracts recorded
within Risk Management Assets, Long-term Risk Management Assets,
Risk Management Liabilities and Long-term Risk Management
Liabilities on our Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008(c) Total (d)
--------- ---- ---- ---- ---- ------- ---------
(in thousands)
Prices Actually Quoted - Exchange
Traded Contracts $267 $(799) $3 $253 $- $- $(276)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (918) 1,864 166 - - - 1,112
Prices Based on Models and Other
Valuation Methods (b) 835 385 80 (21) 290 897 2,466
----- ------- ----- ----- ----- ----- -------
Total $184 $1,450 $249 $232 $290 $897 $3,302
===== ======= ===== ===== ===== ===== =======
(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over-the-counter brokers, industry services,
or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources. Modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(c) There is mark-to-market value in excess of 10 percent of our total
mark-to-market value in individual periods beyond 2008, of which $351
thousand of this mark-to-market value is in 2009.
(d) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $(601)
Changes in Fair Value (a) (2,140)
Reclassifications from AOCI to Net
Income (b) 320
--------
Ending Balance September 30, 2004 $(2,421)
========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $2,326 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
- ---------------------------- -----------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$37 $207 $96 $34 $76 $294 $123 $29
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates primarily related to long-term debt with fixed interest rates was
$13 million and $33 million at September 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore, a near term change in interest rates should
not negatively affect our results of operation or financial position.
AEP TEXAS NORTH COMPANY
STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
--------------------- ---------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $139,905 $104,104 $317,585 $320,733
Sales to AEP Affiliates 12,599 10,351 39,344 46,790
--------- --------- --------- ---------
TOTAL 152,504 114,455 356,929 367,523
--------- --------- --------- ---------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 11,357 9,457 29,518 29,196
Fuel from Affiliates for Electric Generation 15,497 14,390 39,263 31,392
Purchased Electricity for Resale 51,517 22,933 92,822 74,434
Purchased Electricity from AEP Affiliates 309 2,486 4,385 38,280
Other Operation 23,213 23,394 63,150 66,378
Maintenance 4,544 4,552 15,177 14,705
Depreciation and Amortization 9,448 7,132 28,994 26,387
Taxes Other Than Income Taxes 6,476 5,281 16,873 14,746
Income Taxes 8,248 7,411 16,730 21,478
--------- --------- --------- ---------
TOTAL 130,609 97,036 306,912 316,996
--------- --------- --------- ---------
OPERATING INCOME 21,895 17,419 50,017 50,527
Nonoperating Income 8,637 23,572 38,025 54,877
Nonoperating Expenses 8,230 15,211 31,128 43,892
Nonoperating Income Tax Expense 83 2,707 2,186 3,188
Interest Charges 5,366 5,726 17,028 16,290
--------- --------- --------- ---------
Income Before Cumulative Effect of Accounting Changes 16,853 17,347 37,700 42,034
Cumulative Effect of Accounting Changes (Net of Tax) - - - 3,071
--------- --------- --------- ---------
NET INCOME 16,853 17,347 37,700 45,105
Preferred Stock Dividend Requirements 26 26 78 78
--------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $16,827 $17,321 $37,622 $45,027
========= ========= ========= =========
The common stock of TNC is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS NORTH COMPANY
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $137,214 $2,351 $71,942 $(30,763) $180,744
Common Stock Dividends (4,970) (4,970)
Preferred Stock Dividends (78) (78)
Capital Stock Gain 3 3
---------
TOTAL 175,699
---------
COMPREHENSIVE INCOME
- ----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges 130 130
Minimum Pension Liability (7) (7)
NET INCOME 45,105 45,105
---------
TOTAL COMPREHENSIVE INCOME 45,228
--------- ------- --------- --------- ---------
SEPTEMBER 30, 2003 $137,214 $2,351 $112,002 $(30,640) $220,927
========= ======= ========= ========= =========
DECEMBER 31, 2003 $137,214 $2,351 $125,428 $(26,718) $238,275
Common Stock Dividends (2,000) (2,000)
Preferred Stock Dividends (78) (78)
---------
TOTAL 236,197
---------
COMPREHENSIVE INCOME
- ----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,820) (1,820)
NET INCOME 37,700 37,700
---------
TOTAL COMPREHENSIVE INCOME 35,880
--------- ------- --------- --------- ---------
SEPTEMBER 30, 2004 $137,214 $2,351 $161,050 $(28,538) $272,077
========= ======= ========= ========= =========
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -------------------------------------------
Production $362,115 $360,463
Transmission 278,017 268,695
Distribution 469,891 456,278
General 120,781 117,792
Construction Work in Progress 25,669 30,199
----------- -----------
TOTAL 1,256,473 1,233,427
Accumulated Depreciation and Amortization 479,764 460,513
----------- -----------
TOTAL - NET 776,709 772,914
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- -------------------------------------------
Non-Utility Property, Net 1,164 1,286
----------- -----------
CURRENT ASSETS
- -------------------------------------------
Cash and Cash Equivalents 146 -
Other Cash Deposits 2,597 2,863
Advances to Affiliates 54,495 41,593
Accounts Receivable:
Customers 69,684 56,670
Affiliated Companies 27,961 28,910
Accrued Unbilled Revenues 3,611 4,871
Miscellaneous 546 3,411
Allowance for Uncollectible Accounts (770) (175)
Fuel Inventory 7,052 10,925
Materials and Supplies 8,298 8,866
Risk Management Assets 7,304 10,340
Margin Deposits 494 1,285
Prepayments and Other 1,666 1,834
----------- -----------
TOTAL 183,084 171,393
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- -------------------------------------------
Regulatory Assets:
Under Recovery of Fuel Costs 26,680 26,680
Deferred Debt - Restructuring 6,214 6,579
Unamortized Loss on Reacquired Debt 2,489 3,929
Other 2,757 3,332
Long-term Risk Management Assets 3,644 3,106
Deferred Charges 37,457 20,290
----------- -----------
TOTAL 79,241 63,916
----------- -----------
TOTAL ASSETS $1,040,198 $1,009,509
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- --------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares $137,214 $137,214
Paid-in Capital 2,351 2,351
Retained Earnings 161,050 125,428
Accumulated Other Comprehensive Income (Loss) (28,538) (26,718)
----------- -----------
Total Common Shareholder's Equity 272,077 238,275
Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,357 2,357
----------- -----------
Total Shareholders' Equity 274,434 240,632
Long-term Debt 314,333 314,249
----------- -----------
TOTAL 588,767 554,881
----------- -----------
CURRENT LIABILITIES
- --------------------------------------------------------------
Long-term Debt Due Within One Year 18,469 42,505
Accounts Payable:
General 22,846 28,190
Affiliated Companies 41,952 40,601
Customer Deposits 1,503 161
Taxes Accrued 39,756 22,877
Interest Accrued 4,076 6,038
Risk Management Liabilities 9,547 8,658
Obligations Under Capital Leases 198 203
Other 7,162 9,419
----------- -----------
TOTAL 145,509 158,652
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- --------------------------------------------------------------
Deferred Income Taxes 113,021 113,019
Long-term Risk Management Liabilities 1,869 1,094
Regulatory Liabilities:
Asset Removal Costs 80,233 76,740
Deferred Investment Tax Credits 19,016 19,990
Retail Clawback 6,837 11,804
Excess Earnings 13,394 14,262
SFAS 109 Regulatory Liability, Net 12,431 13,655
Other 1,668 1,826
Obligations Under Capital Leases 260 270
Deferred Credits and Other 57,193 43,316
----------- -----------
TOTAL 305,922 295,976
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $1,040,198 $1,009,509
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS NORTH COMPANY
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- -----------------------------------------------------
Net Income $37,700 $45,105
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (3,071)
Depreciation and Amortization 28,994 26,387
Deferred Income Taxes (1,980) 231
Deferred Investment Tax Credits (974) (1,140)
Deferred Property Taxes (4,023) (3,323)
Mark-to-Market of Risk Management Contracts 1,318 (4,786)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (7,345) 10,804
Fuel, Materials and Supplies 4,441 2,658
Accounts Payable, Net (3,993) (40,548)
Taxes Accrued 16,879 8,072
Change in Other Assets (15,653) (11,412)
Change in Other Liabilities 10,350 8,172
-------- --------
Net Cash Flows From Operating Activities 65,714 37,149
-------- --------
INVESTING ACTIVITIES
- -----------------------------------------------------
Construction Expenditures (27,328) (33,136)
Change in Other Cash Deposits, Net 266 (1,442)
Other 510 595
-------- --------
Net Cash Flows Used For Investing Activities (26,552) (33,983)
-------- --------
FINANCING ACTIVITIES
- -----------------------------------------------------
Change in Short-term Debt - Affiliates - (125,000)
Issuance of Long-term Debt - 222,455
Retirement of Long-term Debt (24,036) -
Retirement - Preferred Stock - (10)
Change in Advances to Affiliates (12,902) (95,482)
Dividends Paid on Common Stock (2,000) (4,970)
Dividends Paid on Cumulative Preferred Stock (78) (78)
-------- --------
Net Cash Flows Used For Financing Activities (39,016) (3,085)
-------- --------
Net Increase in Cash and Cash Equivalents 146 81
Cash and Cash Equivalents at Beginning of Period - 62
-------- --------
Cash and Cash Equivalents at End of Period $146 $143
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $17,290,000 and $12,990,000 and for income taxes was $6,905,000 and
$16,410,000 in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries.
AEP TEXAS NORTH COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to TNC's financial statements are combined with the notes to financial
statements for other subsidiary registrants. Listed below are the notes that
apply to TNC.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income for the third quarter of 2004 decreased $7 million from the prior
year period primarily due to increases in Other Operation and Maintenance
expenses coupled with a decrease in Nonoperating Income related to unfavorable
results from risk management activities. The unfavorable impacts in Net Income
were partially offset by decreased Income Taxes.
Net Income for the nine months ended September 30, 2004 decreased $91 million
from the prior year period primarily due to the Cumulative Effect of Accounting
Changes of $77 million recorded in 2003. In addition, increases in Other
Operation, Maintenance and Depreciation and Amortization expenses were partially
offset by decreased Interest Charges and increased Nonoperating Income related
to favorable results from risk management activities.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income for the third quarter of 2004 decreased $4 million from the
prior year period primarily due to:
o A $7 million increase in Other Operation expense primarily due to increased
administrative and support expenses and increased insurance premiums
partially offset by reduced employee-related benefits costs in 2004.
o A $4 million increase in Maintenance expense caused by boiler plant
maintenance at Amos, Glen Lyn, Mountaineer and Sporn plants in 2004.
o A net $3 million increase in fuel and purchased electricity expenses
including a $5 million increase in Fuel for Electric Generation expense
partially offset by decreased purchased electricity expenses. The $5
million increase in Fuel for Electric Generation expense was primarily due
to increased cost of coal consumed partially offset by decreases in
deferred fuel expense and coal pile inventory survey adjustments.
o A $2 million increase in Depreciation and Amortization expense relating to
a greater depreciable base in 2004 including the addition of capitalized
software costs partially offset by reduced amortization for Virginia's
transition generation regulatory assets. The reduced amortization is
related to the extension of the transition period for electricity
restructuring.
The decrease in Operating Income for the third quarter of 2004 was partially
offset by:
o An $8 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
o A $4 million increase in Sales to AEP Affiliates reflecting a higher
average price in MWH.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $7 million in the third quarter of 2004 compared
to the prior year period primarily due to unfavorable results from risk
management activities.
Nonoperating Expenses decreased $2 million in the third quarter of 2004 compared
to the prior year period due to a charitable donation in 2003 and decreased
expenses of inactive coal companies.
Interest charges decreased $1 million in the third quarter of 2004 compared to
the prior year period due to reduced interest rates from refinancing higher cost
debt.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 29.6% 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, 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.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income for the nine months ended September 30, 2004 in comparison to
the prior year period decreased $33 million primarily due to:
o A $29 million increase in Maintenance expenses caused by boiler plant
maintenance at Amos, Clinch River, Glen Lyn and Kanawha River plants.
o A $17 million increase in Other Operation expenses primarily due to
increased administrative and support expenses, increased insurance premiums
and increased removal costs. These increases were partially offset by
reduced labor costs in 2004.
o A $15 million increase in Depreciation and Amortization expense primarily
due to reduced expense in 2003 attributable to the adoption of SFAS 143
for regulated operations and to a lesser degree, a greater depreciable
base in 2004, which included the addition of capitalized software costs
partially offset by reduced amortization of Virginia's transition
generation regulatory assets. The reduced amortization is related to the
extension of the transition period for electricity restructuring.
o A $4 million decrease in Sales to AEP Affiliates relating to decreased
power available for sale caused by planned plant outages in 2004.
The decrease in Operating Income for the nine months ended September 30, 2004
was partially offset by:
o A $17 million increase in Electric Generation, Transmission and Distribution
revenues primarily resulting from a 28% increase in cooling degree days in
2004 in comparison to the prior year period.
o A $10 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
o A net $4 million decrease in fuel and purchased electricity expenses
including a $19 million decrease in Fuel for Electric Generation expenses
partially offset by a $15 million increase in purchased electricity
expenses. The decrease in Fuel for Electric Generation expenses was
primarily due to decreased generation and deferred fuel expense partially
offset by the increased cost of coal used in generation. Purchased
electricity expenses increased due to lower generation caused by planned
outages partially offset by decreased capacity charges.
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $6 million in the nine months ended September 30,
2004 compared to the prior year period primarily due to favorable results from
risk management activities.
Nonoperating Expenses decreased $3 million in the nine months ended September
30, 2004 compared to the prior year period due to decreased expenses of inactive
coal companies.
Nonoperating Income Tax Credit decreased $4 million. See Income Taxes section
below for further discussion.
Interest Charges decreased $13 million in the nine months ended September 30,
2004 compared to the prior year period due to reduced interest rates from
refinancing higher cost debt and increased construction-related capitalized
interest.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were 37.3%
and 36.7%, 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, amortization of investment tax
credits and state income taxes. The effective tax rates remained relatively flat
for the comparative period.
Cumulative Effect of Accounting Changes
- ---------------------------------------
The Cumulative Effect of Accounting Changes of $77 million is due to the
implementation of SFAS 143 and EITF 02-3 in 2003.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds Baa1 BBB A-
Senior Unsecured Debt Baa2 BBB BBB+
Cash Flow
- ---------
Cash flows for the nine months ended September 30, 2004 and 2003 were as
follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $4,561 $4,133
--------- ---------
Cash flow from (used for):
Operating activities 397,919 409,707
Investing activities (261,198) (187,977)
Financing activities (137,784) (220,755)
--------- ---------
Net increase (decrease) in cash and cash equivalents (1,063) 975
--------- ---------
Cash and cash equivalents at end of period $3,498 $5,108
========= =========
Operating Activities
- --------------------
Net Cash Flows From Operating Activities for the nine months ended September 30,
2004 were $398 million. We produced income of $126 million that included noncash
expense items of $191 million for depreciation, amortization and deferred taxes.
The other changes in assets and liabilities primarily represent items that had a
current period cash flow impact such as changes in working capital, the largest
of which were affiliated accounts receivable.
Investing Activities
- --------------------
Net Cash Flows Used For Investing Activities for the nine months ended September
30, 2004 were $261 million. Current year construction expenditures of $305
million were focused primarily on projects to improve service reliability for
transmission and distribution, as well as environmental upgrades. In addition,
Changes in Other Cash Deposits, Net of $41 million consisted primarily of monies
set aside in 2003 for the retirement of the Installment Purchase Contracts in
2004. For the remainder of 2004, we expect our Construction Expenditures to be
approximately $105 million.
Financing Activities
- --------------------
For the nine months ended September 30, 2004, we issued $126 million of Senior
Unsecured Notes and we retired $66 million of First Mortgage Bonds and $40
million of Installment Purchase Contracts. In addition, we repaid $83 million of
advances from affiliates and advanced $24 million to our affiliates and we paid
$50 million in common dividends.
Liquidity
- ---------
We have solid investment grade ratings which provide us ready access to capital
markets in order to refinance long-term debt maturities. In addition, we
participate in the AEP Utility Money Pool, which provides us access to
liquidity of the AEP System.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first nine months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Senior Unsecured Notes $125,000 Variable 2007
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $45,000 7.125 2024
Installment Purchase Contracts 40,000 5.45 2019
First Mortgage Bonds 21,000 7.70 2004
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $68,066
(Gain) Loss from Contracts Realized/Settled During the Period (a) (32,269)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) (345)
Change in Fair Value Due to Valuation Methodology Changes (d) 835
Changes in Fair Value of Risk Management Contracts (e) 4,229
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f) 2,907
--------
Total MTM Risk Management Contract Net Assets 43,423
Net Cash Flow Hedge Contracts (g) (21,364)
DETM Assignment (h) (25,781)
--------
Total MTM Risk Management Contract Net Liabilities at September 30, 2004 $(3,722)
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather, etc.
(f) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(h) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of September 30, 2004
MTM Risk
Management Cash Flow DETM
Contracts(a) Hedges Assignment (b) Consolidated (c)
------------ --------- -------------- ----------------
(in thousands)
Current Assets $87,524 $1,560 $- $89,084
Non Current Assets 81,202 207 - 81,409
--------- --------- --------- ---------
Total MTM Derivative
Contract Assets 168,726 1,767 - 170,493
--------- --------- --------- ---------
Current Liabilities (80,289) (21,485) (10,624) (112,398)
Non Current Liabilities (45,014) (1,646) (15,157) (61,817)
--------- --------- --------- ---------
Total MTM Derivative
Contract Liabilities (125,303) (23,131) (25,781) (174,215)
--------- --------- --------- ---------
Total MTM Derivative
Contract Net Assets
(Liabilities) $43,423 $(21,364) $(25,781) $(3,722)
========= ========= ========= =========
(a) Does not include Cash Flow Hedges.
(b) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
(c) Represents amount of total MTM derivative contracts recorded within
Risk Management Assets, Long-term Risk Management Assets, Risk
Management Liabilities and Long-term Risk Management Liabilities on our
Consolidated Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 (c) Total (d)
--------- ---- ---- ---- ---- -------- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $2,180 $(6,524) $28 $2,066 $- $- $(2,250)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (3,024) 12,677 3,296 2,095 - - 15,044
Prices Based on Models and Other
Valuation Methods (b) 769 3,196 4,231 3,527 5,832 13,074 30,629
------- -------- ------- ------ ------- -------- --------
Total $(75) $9,349 $7,555 $7,688 $5,832 $13,074 $43,423
======= ======== ======= ====== ======= ======== ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources. Modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(c) There is mark-to-market value in excess of 10 percent of our total
mark-to-market value in individual periods beyond 2008. $5.9 million of this
mark-to-market value is in 2009 and $5.8 million of this mark-to-market is
in 2010.
(d) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
Foreign
Power Currency Interest Rate Consolidated
----- -------- ------------- ------------
(in thousands)
Beginning Balance December 31, 2003 $359 $(183) $(1,745) $(1,569)
Changes in Fair Value (a) (2,658) - (10,622) (13,280)
Reclassifications from AOCI to Net
Income (b) (1,363) 5 272 (1,086)
-------- ------ --------- ---------
Ending Balance September 30, 2004 $(3,662) $(178) $(12,095) $(15,935)
======== ====== ========= =========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $3,876 thousand loss.
Credit Risk
- -----------
Counterparty credit quality and exposure is generally consistent with that of
AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
----------------------------- -----------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$304 $1,690 $786 $274 $596 $2,314 $969 $230
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates primarily related to long-term debt with fixed interest rates was
$109 million and $102 million at September 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period; therefore, a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
------------------- ---------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ----------------------------------------------------
Electric Generation, Transmission and Distribution $428,689 $428,667 $1,314,647 $1,297,255
Sales to AEP Affiliates 58,726 54,944 163,655 167,335
--------- --------- ----------- -----------
TOTAL 487,415 483,611 1,478,302 1,464,590
--------- --------- ----------- -----------
OPERATING EXPENSES
- ----------------------------------------------------
Fuel for Electric Generation 117,841 113,274 327,246 345,819
Purchased Electricity for Resale 19,727 18,365 54,157 50,745
Purchased Electricity from AEP Affiliates 90,257 92,857 268,537 257,382
Other Operation 70,725 64,065 209,393 192,806
Maintenance 36,240 31,855 130,493 101,420
Depreciation and Amortization 48,877 46,501 144,021 128,574
Taxes Other Than Income Taxes 22,995 23,232 69,947 70,583
Income Taxes 18,063 26,328 78,339 88,387
--------- --------- ----------- -----------
TOTAL 424,725 416,477 1,282,133 1,235,716
--------- --------- ----------- -----------
OPERATING INCOME 62,690 67,134 196,169 228,874
Nonoperating Income 636 7,502 9,336 2,878
Nonoperating Expenses 1,497 3,910 7,239 10,219
Nonoperating Income Tax Credit (1,899) (1,307) (3,524) (7,491)
Interest Charges 25,269 26,318 76,169 89,520
--------- --------- ----------- -----------
Income Before Cumulative Effect of Accounting Changes 38,459 45,715 125,621 139,504
Cumulative Effect of Accounting Changes (Net of Tax) - - - 77,257
--------- --------- ----------- -----------
NET INCOME 38,459 45,715 125,621 216,761
Preferred Stock Dividend Requirements
(Including Capital Stock Expense) 796 703 2,417 2,671
--------- --------- ----------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $37,663 $45,012 $123,204 $214,090
========= ========= =========== ===========
The common stock of APCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $260,458 $717,242 $260,439 $(72,082) $1,166,057
Common Stock Dividends (96,200) (96,200)
Preferred Stock Dividends (801) (801)
Capital Stock Expense 1,870 (1,870) -
SFAS 71 Reapplication 162 162
-----------
TOTAL 1,069,218
-----------
COMPREHENSIVE INCOME
- -------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges 772 772
NET INCOME 216,761 216,761
-----------
TOTAL COMPREHENSIVE INCOME 217,533
--------- --------- --------- --------- -----------
SEPTEMBER 30, 2003 $260,458 $719,274 $378,329 $(71,310) $1,286,751
========= ========= ========= ========= ===========
DECEMBER 31, 2003 $260,458 $719,899 $408,718 $(52,088) $1,336,987
Common Stock Dividends (50,000) (50,000)
Preferred Stock Dividends (600) (600)
Capital Stock Expense 1,817 (1,817) -
-----------
TOTAL 1,286,387
-----------
COMPREHENSIVE INCOME
- -------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (14,366) (14,366)
NET INCOME 125,621 125,621
-----------
TOTAL COMPREHENSIVE INCOME 111,255
--------- --------- --------- --------- -----------
SEPTEMBER 30, 2004 $260,458 $721,716 $481,922 $(66,454) $1,397,642
========= ========= ========= ========= ===========
See Notes to Financial Statements of Registrant Subsidiaries.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ----------------------------------------------
Production $2,488,089 $2,287,043
Transmission 1,251,486 1,240,889
Distribution 2,051,936 2,006,329
General 307,207 294,786
Construction Work in Progress 302,750 311,884
----------- -----------
TOTAL 6,401,468 6,140,931
Accumulated Depreciation and Amortization 2,413,097 2,321,360
----------- -----------
TOTAL - NET 3,988,371 3,819,571
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ----------------------------------------------
Non-Utility Property, Net 20,619 20,574
Other Investments 21,337 26,668
----------- -----------
TOTAL 41,956 47,242
----------- -----------
CURRENT ASSETS
- ----------------------------------------------
Cash and Cash Equivalents 3,498 4,561
Other Cash Deposits 707 41,320
Advances to Affiliates, Net 23,779 -
Accounts Receivable:
Customers 125,478 133,717
Affiliated Companies 95,975 137,281
Accrued Unbilled Revenues 31,582 35,020
Miscellaneous 1,076 3,961
Allowance for Uncollectible Accounts (5,951) (2,085)
Fuel Inventory 48,511 42,806
Materials and Supplies 87,932 71,978
Risk Management Assets 89,084 71,189
Margin Deposits 5,421 11,525
Prepayments and Other 14,776 13,301
----------- -----------
TOTAL 521,868 564,574
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ----------------------------------------------
Regulatory Assets:
Transition Regulatory Assets 26,528 30,855
SFAS 109 Regulatory Asset, Net 324,032 325,889
Unamortized Loss on Reacquired Debt 18,774 19,005
Other 41,512 41,447
Long-term Risk Management Assets 81,409 70,900
Deferred Property Taxes 20,769 35,343
Other Deferred Charges 23,552 22,185
----------- -----------
TOTAL 536,576 545,624
----------- -----------
TOTAL ASSETS $5,088,771 $4,977,011
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ------------------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $260,458 $260,458
Paid-in Capital 721,716 719,899
Retained Earnings 481,922 408,718
Accumulated Other Comprehensive Income (Loss) (66,454) (52,088)
----------- -----------
Total Common Shareholder's Equity 1,397,642 1,336,987
Cumulative Preferred Stock Not Subject to Mandatory Redemption 17,784 17,784
----------- -----------
Total Shareholders' Equity 1,415,426 1,354,771
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption 5,360 5,360
Long-term Debt 1,254,921 1,703,073
----------- -----------
TOTAL 2,675,707 3,063,204
----------- -----------
CURRENT LIABILITIES
- ------------------------------------------------------------------------
Long-term Debt Due Within One Year 630,009 161,008
Advances from Affiliates, Net - 82,994
Accounts Payable:
General 132,417 140,497
Affiliated Companies 60,150 81,812
Customer Deposits 45,867 33,930
Taxes Accrued 80,616 50,259
Interest Accrued 38,820 22,113
Risk Management Liabilities 112,398 51,430
Obligations Under Capital Leases 7,179 9,218
Other 53,785 60,289
----------- -----------
TOTAL 1,161,241 693,550
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ------------------------------------------------------------------------
Deferred Income Taxes 825,347 803,355
Regulatory Liabilities:
Asset Removal Costs 98,139 92,497
Deferred Investment Tax Credits 31,546 30,545
Over-Recovery of Fuel Cost 65,036 68,704
Other Regulatory Liabilities 20,423 17,326
Long-term Risk Management Liabilities 61,817 54,327
Obligations Under Capital Leases 13,679 16,134
Asset Retirement Obligation 22,635 21,776
Deferred Credits and Other 113,201 115,593
----------- -----------
TOTAL 1,251,823 1,220,257
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $5,088,771 $4,977,011
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------
Net Income $125,621 $216,761
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (77,257)
Depreciation and Amortization 144,021 128,574
Deferred Income Taxes 31,596 3,394
Deferred Investment Tax Credits 1,001 (1,940)
Deferred Property Taxes 14,574 15,008
Deferred Power Supply Costs, Net (3,668) 71,815
Mark to Market of Risk Management Contracts 18,137 33,727
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 59,734 68,673
Fuel, Materials and Supplies (21,659) 6,202
Accounts Payable, Net (29,742) (57,931)
Customer Deposits 11,937 5,590
Taxes Accrued 30,357 18,001
Interest Accrued 16,707 20,354
Incentive Plan Accrued (1,151) (8,789)
Rate Stabilization Deferral - (75,601)
Change in Other Assets 3,294 6,162
Change in Other Liabilities (2,840) 36,964
--------- ---------
Net Cash Flows From Operating Activities 397,919 409,707
--------- ---------
INVESTING ACTIVITIES
- ------------------------------------------------------
Construction Expenditures (305,055) (190,047)
Proceeds from Sale of Property and Other 3,244 2,078
Change in Other Cash Deposits, Net 40,613 (8)
--------- ---------
Net Cash Flows Used For Investing Activities (261,198) (187,977)
--------- ---------
FINANCING ACTIVITIES
- ------------------------------------------------------
Issuance of Long-term Debt 125,595 495,122
Retirement of Long-term Debt (106,006) (545,237)
Change in Advances to/from Affiliates, Net (106,773) (73,639)
Dividends Paid on Common Stock (50,000) (96,200)
Dividends Paid on Cumulative Preferred Stock (600) (801)
--------- ---------
Net Cash Flows Used For Financing Activities (137,784) (220,755)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (1,063) 975
Cash and Cash Equivalents at Beginning of Period 4,561 4,133
--------- ---------
Cash and Cash Equivalents at End of Period $3,498 $5,108
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $53,622,000 and $63,481,000 and for income taxes was $(831,000)
and $47,419,000 in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to APCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below are
the notes that apply to APCo.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
The decrease in Net Income of $10 million in third quarter 2004 was primarily
due to decreases in operating revenues and nonoperating risk management
activities.
The decrease in year-to-date Net Income of $29 million in 2004 was primarily due
to a $27 million net-of-tax Cumulative Effect of Accounting Changes in the first
quarter of 2003.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $6 million primarily due to:
o A $6 million decrease in retail electric revenues resulting from decreased
weather-based demand from residential customers and decreased industrial
sales due to a declining number of customers.
o A $3 million increase in Other Operation expenses primarily relating to
lime expenses for pollution control and increases in steam power expenses
and administrative and support expenses.
o A $3 million increase in Depreciation and Amortization expenses due to a
greater depreciable base in 2004, including capitalized software costs and
the increased amortization of transition generation regulatory assets due
to normal operating adjustments.
The decrease in Operating Income was partially offset by:
o A $6 million decrease in Income Taxes expense. See Income Taxes section
below for further discussion.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $2 million due to unfavorable results from risk
management activities.
Interest Charges increased $2 million due to the write-off of costs related to
reacquired debt that was refinanced at lower interest rates.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 31.5% and
32.7% 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, amortization of investment tax
credits and state income taxes. The effective tax rates remained relatively flat
for the comparative period.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $5 million primarily due to:
o A $12 million decrease in non-affiliated wholesale energy sales due to lower
sales volume and the expiration of municipal contracts.
o An $11 million increase in Other Operation expenses primarily relating to
lime expenses for pollution control and increases in steam power expenses
and administrative and support expenses.
o A $10 million increase in Depreciation and Amortization expenses due to a
greater depreciable base in 2004, including capitalized software costs and
the increased amortization of transition generation regulatory assets due
to normal operating adjustments.
o A $7 million increase in fuel expenses due to higher coal costs.
o A $3 million increase in Maintenance expenses due primarily to boiler
overhaul work from scheduled and forced outages.
The decrease in Operating Income was partially offset by:
o A $24 million increase in retail electric revenues resulting primarily from
increased weather-related demand from residential and commercial customers
during the second quarter 2004.
o A $9 million increase in operating revenues related to favorable results
from risk management activities.
o A $6 million decrease in Income Taxes expense. See Income Taxes section
below for further discussion.
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $10 million due to favorable results from risk
management activities.
Nonoperating Income Tax Credit decreased $5 million. See Income Taxes section
below for further discussion.
Interest Charges increased $3 million due to the write-off of costs related to
reacquired debt that was refinanced at lower interest rates.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were 33.6%
and 33.4% 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, amortization of investment tax
credits and state income taxes. The effective tax rates remained relatively flat
for the comparative period.
Cumulative Effect of Accounting Changes
- ---------------------------------------
The Cumulative Effect of Accounting Changes is due to the one-time, after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
Senior Unsecured Debt A3 BBB A-
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first nine months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase Contracts $43,695 Variable 2038
Installment Purchase Contracts 48,550 Variable 2038
Notes Payable - Affiliates 100,000 4.64 2010
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $11,000 7.60 2024
Installment Purchase Contracts 43,695 6.25 2020
Installment Purchase Contracts 48,550 6.375 2020
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $38,337
(Gain) Loss from Contracts Realized/Settled During the Period (a) (18,594)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) (200)
Change in Fair Value Due to Valuation Methodology Changes (d) 898
Changes in Fair Value of Risk Management Contracts (e) 4,469
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f) -
--------
Total MTM Risk Management Contract Net Assets 24,910
Net Cash Flow Hedge Contracts (g) (3,273)
DETM Assignment (h) (14,888)
--------
Total MTM Risk Management Contract Net Assets at September 30, 2004 $6,749
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather, etc.
(f) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(h) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of September 30, 2004
MTM Risk
Management Cash Flow DETM
Contracts(a) Hedges Assignment (b) Consolidated (c)
------------ --------- -------------- ----------------
(in thousands)
Current Assets $50,378 $393 $- $50,771
Non Current Assets 46,895 119 - 47,014
-------- -------- --------- --------
Total MTM Derivative
Contract Assets 97,273 512 - 97,785
-------- -------- --------- --------
Current Liabilities (46,368) (2,969) (6,135) (55,472)
Non Current Liabilities (25,995) (816) (8,753) (35,564)
-------- -------- --------- --------
Total MTM Derivative
Contract Liabilities (72,363) (3,785) (14,888) (91,036)
-------- -------- --------- --------
Total MTM Derivative
Contract Net Assets
(Liabilities)
$24,910 $(3,273) $(14,888) $6,749
======== ======== ========= ========
(a) Does not include Cash Flow Hedges.
(b) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
(c) Represents amount of total MTM derivative contracts recorded within
Risk Management Assets, Long-term Risk Management Assets, Risk Management
Liabilities and Long-term Risk Management Liabilities on our Consolidated
Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 (c) Total (d)
-------------- -------- -------- -------- -------- -------- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $1,259 $(3,767) $16 $1,193 $- $- $(1,299)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (1,746) 7,153 1,904 1,210 - - 8,521
Prices Based on Models and Other
Valuation Methods (b) 441 1,847 2,443 2,037 3,369 7,551 17,688
------- -------- ------- ------- ------- ------- --------
Total $(46) $5,233 $4,363 $4,440 $3,369 $7,551 $24,910
======= ======== ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over-the-counter brokers, industry services, or
multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" if there is absence of
pricing information from external sources. Modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(c) There is mark-to-market value in excess of 10 percent of our total
mark-to-market value in individual periods beyond 2008. $3.4 million of
this mark-to-market value is in 2009 and $3.3 million of this
mark-to-market is in 2010.
(d) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $202
Changes in Fair Value (a) (1,473)
Reclassifications from AOCI to Net Income (b) (844)
--------
Ending Balance September 30, 2004 $(2,115)
========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,662 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Energy and Gas Risk Management Contracts
- ------------------------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
----------------------------- -----------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$176 $976 $454 $158 $336 $1,303 $546 $130
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates primarily related to long-term debt with fixed interest rates was
$78 million and $98 million at September 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
-------------------- --------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- -----------------------------------------------------
Electric Generation, Transmission and Distribution $369,192 $375,936 $1,049,671 $1,027,732
Sales to AEP Affiliates 21,796 21,719 61,748 62,199
--------- --------- ----------- -----------
TOTAL 390,988 397,655 1,111,419 1,089,931
--------- --------- ----------- -----------
OPERATING EXPENSES
- -----------------------------------------------------
Fuel for Electric Generation 49,732 42,473 142,528 127,937
Fuel From Affiliates for Electric Generation - 7,882 10,603 18,485
Purchased Electricity for Resale 5,389 5,688 14,839 13,898
Purchased Electricity from AEP Affiliates 96,193 93,486 263,614 263,225
Other Operation 60,520 57,348 176,797 166,027
Maintenance 17,417 19,630 60,187 56,801
Depreciation and Amortization 37,933 34,442 111,196 101,478
Taxes Other Than Income Taxes 34,017 34,970 102,069 101,532
Income Taxes 24,525 30,543 65,187 70,787
--------- --------- ----------- -----------
TOTAL 325,726 326,462 947,020 920,170
--------- --------- ----------- -----------
OPERATING INCOME 65,262 71,193 164,399 169,761
Nonoperating Income (Loss) 1,808 3,778 7,656 (2,587)
Nonoperating Expenses 444 159 2,037 2,944
Nonoperating Income Tax Credit 383 84 92 5,231
Interest Charges 14,439 12,071 41,666 38,946
--------- --------- ----------- -----------
Income Before Cumulative Effect of Accounting Changes 52,570 62,825 128,444 130,515
Cumulative Effect of Accounting Changes (Net of Tax) - - - 27,283
--------- --------- ----------- -----------
NET INCOME 52,570 62,825 128,444 157,798
Preferred Stock - Capital Stock Expense 254 254 762 762
--------- --------- ----------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $52,316 $62,571 $127,682 $157,036
========= ========= =========== ===========
The common stock of CSPCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $41,026 $575,384 $290,611 $(59,357) $847,664
Common Stock Dividends Declared (124,932) (124,932)
Capital Stock Expense 762 (762) -
---------
TOTAL 722,732
---------
COMPREHENSIVE INCOME
- -------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges 755 755
NET INCOME 157,798 157,798
---------
TOTAL COMPREHENSIVE INCOME 158,553
-------- --------- --------- --------- ---------
SEPTEMBER 30, 2003 $41,026 $576,146 $322,715 $(58,602) $881,285
======== ========= ========= ========= =========
DECEMBER 31, 2003 $41,026 $576,400 $326,782 $(46,327) $897,881
Common Stock Dividends Declared (93,750) (93,750)
Capital Stock Expense 762 (762) -
---------
TOTAL 804,131
---------
COMPREHENSIVE INCOME
- -------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (2,317) (2,317)
NET INCOME 128,444 128,444
---------
TOTAL COMPREHENSIVE INCOME 126,127
-------- --------- --------- --------- ---------
SEPTEMBER 30, 2004 $41,026 $577,162 $360,714 $(48,644) $930,258
======== ========= ========= ========= =========
See Notes to Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- --------------------------------------------------
Production $1,652,487 $1,610,888
Transmission 431,021 425,512
Distribution 1,291,414 1,253,760
General 171,576 166,002
Construction Work in Progress 107,284 114,281
----------- -----------
TOTAL 3,653,782 3,570,443
Accumulated Depreciation and Amortization 1,454,558 1,389,586
----------- -----------
TOTAL - NET 2,199,224 2,180,857
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- --------------------------------------------------
Non-Utility Property, Net 22,309 22,417
Other Investments 6,065 8,663
----------- -----------
TOTAL 28,374 31,080
----------- -----------
CURRENT ASSETS
- --------------------------------------------------
Cash and Cash Equivalents 3,313 3,377
Other Cash Deposits 99 765
Advances to Affiliates 158,371 -
Accounts Receivable:
Customers 39,945 47,099
Affiliated Companies 53,568 68,168
Accrued Unbilled Revenues 26,201 23,723
Miscellaneous 554 5,257
Allowance for Uncollectible Accounts (794) (531)
Fuel 27,423 14,365
Materials and Supplies 70,891 44,377
Risk Management Assets 50,771 40,095
Margin Deposits 3,185 6,636
Prepayments and Other 12,937 12,444
----------- -----------
TOTAL 446,464 265,775
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- --------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Assets, Net 16,371 16,027
Transition Regulatory Assets 164,434 188,532
Unamortized Loss on Reacquired Debt 13,346 13,659
Other 30,227 24,966
Long-term Risk Management Assets 47,014 39,932
Deferred Property Taxes 15,750 62,262
Deferred Charges 17,469 15,276
----------- -----------
TOTAL 304,611 360,654
----------- -----------
TOTAL ASSETS $2,978,673 $2,838,366
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ---------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $41,026 $41,026
Paid-in Capital 577,162 576,400
Retained Earnings 360,714 326,782
Accumulated Other Comprehensive Income (Loss) (48,644) (46,327)
----------- -----------
Total Common Shareholder's Equity 930,258 897,881
Long-term Debt:
Nonaffiliated 887,560 886,564
Affiliated 100,000 -
----------- -----------
Total Long-term Debt 987,560 886,564
----------- -----------
TOTAL 1,917,818 1,784,445
----------- -----------
CURRENT LIABILITIES
- ---------------------------------------------------
Long-term Debt Due Within One Year - 11,000
Advances from Affiliates, Net - 6,517
Accounts Payable:
General 49,721 58,220
Affiliated Companies 46,536 53,572
Customer Deposits 26,412 19,727
Taxes Accrued 134,968 132,853
Interest Accrued 7,888 16,528
Risk Management Liabilities 55,472 28,966
Obligations Under Capital Leases 4,126 4,221
Other 22,555 25,364
----------- -----------
TOTAL 347,678 356,968
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ---------------------------------------------------
Deferred Income Taxes 467,804 458,498
Regulatory Liabilities:
Asset Removal Costs 103,112 99,119
Deferred Investment Tax Credits 28,664 30,797
Long-term Risk Management Liabilities 35,564 30,598
Obligations Under Capital Leases 8,892 11,397
Asset Retirement Obligations 9,262 8,740
Deferred Credits and Other 59,879 57,804
----------- -----------
TOTAL 713,177 696,953
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $2,978,673 $2,838,366
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------
Net Income $128,444 $157,798
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (27,283)
Depreciation and Amortization 111,196 101,478
Deferred Income Taxes 10,210 (3,942)
Deferred Investment Tax Credits (2,133) (2,288)
Deferred Property Taxes 46,512 46,478
Mark-to-Market of Risk Management Contracts 10,130 29,056
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 24,242 27,106
Fuel, Materials and Supplies (39,572) 3,326
Accounts Payable (15,535) (74,407)
Taxes Accrued 2,115 (33,868)
Interest Accrued (8,640) (2,054)
Change in Other Assets (6,865) (12,532)
Change in Other Liabilities 9,225 (2,347)
--------- --------
Net Cash Flows From Operating Activities 269,329 206,521
--------- --------
INVESTING ACTIVITIES
- ------------------------------------------------------
Construction Expenditures (101,656) (98,032)
Proceeds from Sale of Property and Other 3,423 190
Change in Other Cash Deposits, Net 666 16
--------- --------
Net Cash Flows Used For Investing Activities (97,567) (97,826)
--------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated 90,057 494,350
Issuance of Long-term Debt - Affiliated 100,000 -
Change in Advances to/from Affiliates, Net (164,888) 182,832
Retirement of Long-term Debt - Nonaffiliated (103,245) (207,500)
Retirement of Long-term Debt - Affiliated - (160,000)
Change in Short-term Debt - Affiliates - (290,000)
Dividends Paid on Common Stock (93,750) (124,932)
--------- --------
Net Cash Flows Used For Financing Activities (171,826) (105,250)
--------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (64) 3,445
Cash and Cash Equivalents at Beginning of Period 3,377 697
--------- --------
Cash and Cash Equivalents at End of Period $3,313 $4,142
========= ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $46,034,000 and $39,804,000 and for income taxes was $(5,282,000)
and $48,955,000 in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to CSPCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below are
the notes that apply to CSPCo.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income increased $14 million for the third quarter of 2004 and $58 million
for the first nine months of 2004. The increases in Net Income reflect
improvement in retail sales, the end of amortization of Cook Plant outage
settlements and reduced financing charges in both the quarter and year-to-date
periods and favorable results from risk management activities for the
year-to-date period.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income increased $11 million primarily due to:
o A $17 million increase in Electric Generation, Transmission and Distribution
revenues primarily due to an increase in commercial and industrial sales
reflecting the economic recovery and the end of amortization of Cook outage
settlements.
o A $9 million decrease in Other Operation expenses reflecting the end of
amortization of Cook Plant outage settlements.
o A $5 million decrease in Maintenance expenses primarily due to the end of
amortization of Cook Plant outage settlements and decreased storm damage
expenses.
o A $5 million decrease in Taxes Other Than Income Taxes primarily due to
prior year accrual adjustments for Indiana real and personal property taxes
related to reassessed property values and tax rates.
o A $3 million increase in Sales to AEP Affiliates reflecting increased
availability of Cook Plant units.
The increase in Operating Income was partially offset by:
o A $13 million increase in Income Taxes. See Income Taxes section below for
further discussion.
o A $7 million increase in Fuel for Electric Generation expenses due to
increased generation and higher fuel costs.
o A $6 million increase in Purchased Electricity from AEP Affiliates
reflecting increased generation and higher fuel costs for power acquired
under an AEGCo unit power agreement.
Other Impacts on Earnings
- -------------------------
Nonoperating Income Tax Expense decreased $2 million. See Income Taxes section
below for further discussion.
Interest Charges decreased $3 million primarily due to a reduction in
outstanding long-term debt and lower interest rates from refunding higher cost
debt.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 34.5% and
29.5% 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, amortization of investment tax
credits and state income taxes. The increase in the effective tax rate is
primarily due to permanent differences related to tax-exempt interest income,
offset by federal income tax return adjustments.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income increased $33 million primarily due to:
o A $44 million increase in Electric Generation, Transmission and
Distribution revenues due to an increase in commercial and industrial
sales reflecting the economic recovery and the end of amortization of Cook
Plant outage settlements.
o A $13 million decrease in Other Operation expenses including the end of
amortization of Cook Plant outage settlements.
o A $5 million decrease in Purchased Electricity from AEP Affiliates
primarily due to an 8% increase in net generation that reduced our need to
purchase power from affiliates.
o A $4 million decrease in Taxes Other Than Income Taxes primarily due to
prior year accrual adjustments for Indiana real and personal property taxes
related to reassessed property values and tax rates.
o A $2 million decrease in Fuel for Electric Generation expenses reflecting
a change in fuel mix as nuclear generation increased 32% and coal-fired
generation declined 12% due to generating unit availability.
The increase in Operating Income was partially offset by:
o A $26 million increase in Income Taxes. See Income Taxes section below for
further discussion.
o A $6 million increase in Maintenance expenses primarily due to both
planned and forced outages at Rockport and Tanners Creek plants,
increased costs for distribution right of way, line maintenance and cost
of storm damage.
o A $3 million decrease in Sales to AEP Affiliates due to lower capacity
revenues partially offset by increased energy sales to our affiliates.
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $18 million primarily due to favorable results
from risk management activities and increased barging revenues.
Nonoperating Expenses increased $3 million primarily due to increased costs for
barging activities.
Nonoperating Income Tax Expense increased $6 million. See Income Taxes section
below for further discussion.
Interest Charges decreased $13 million primarily due to a reduction in
outstanding long-term debt and lower interest rates from refunding higher cost
debt.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were 36.1%
and 35.5% 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, amortization of investment tax
credits and state income taxes. The effective tax rates remained relatively flat
for the comparative period.
Cumulative Effect of Accounting Change
- --------------------------------------
The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 related to mark-to-market accounting for risk
management contracts that are not derivatives.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
Senior Unsecured Debt Baa2 BBB BBB
Cash Flow
- ---------
Cash flows for the first nine months of 2004 and 2003 were as follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $3,899 $3,251
--------- ---------
Cash flow from (used for):
Operating activities 407,169 191,018
Investing activities (121,913) (106,574)
Financing activities (286,774) (83,634)
--------- ---------
Net increase (decrease) in cash and cash equivalents (1,518) 810
--------- ---------
Cash and cash equivalents at end of period $2,381 $4,061
========= =========
Operating Activities
- --------------------
Our cash flows from operating activities were $407 million for the first nine
months of 2004. We produced income of $122 million during the period including
noncash expense items of $126 million for depreciation, amortization and
deferred income taxes. In addition, there is a current period impact for a net
$11 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 increases in the balance of fuel, materials and supplies of $20
million and the balance of accrued taxes of $55 million and a net change in
accounts receivable and payable of $18 million.
Investing Activities
- --------------------
Cash Flows Used For Investing Activities during 2004 were $122 million due to
construction expenditures. Construction expenditures for nuclear and coal
generation, transmission and distribution assets were incurred to upgrade or
replace equipment and improve reliability. For the remainder of 2004, we expect
our Construction Expenditures to be approximately $49 million.
Financing Activities
- --------------------
During the first nine months of 2004, we used cash of $205 million to retire
long-term debt and $79 million to pay common dividends. These activities were
supported by the generation of $407 million in cash flow from operations.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first nine months of 2004
were:
Issuances
---------
None.
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $30,000 7.20 2024
First Mortgage Bonds 25,000 7.50 2024
Senior Unsecured Notes 150,000 6.875 2004
We anticipate issuing long-term debt during the fourth quarter.
Off-Balance Sheet Arrangements
- ------------------------------
We enter into off-balance sheet arrangements for various 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 are entered in the
normal course of business. Our off-balance sheet arrangements have not changed
significantly since year-end. For complete information on our off-balance sheet
arrangements see "Off-balance Sheet Arrangements" in "Management's Financial
Discussion and Analysis" section of our 2003 Annual Report.
Spent Nuclear Fuel Disposal
- ---------------------------
As a result of DOE's failure to make sufficient progress toward a permanent
repository or otherwise assume responsibility for spent nuclear fuel (SNF), we
and South Texas Project Nuclear Operating Company, along with a number of
unaffiliated utilities and states, filed suit in the D.C. Circuit Court
requesting, among other things, that the D.C. Circuit Court order DOE to meet
its obligations under the law. The D.C. Circuit Court ordered the parties to
proceed with contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, we filed a complaint in the U.S. Court of
Federal Claims seeking damages in excess of $150 million due to the DOE's
partial material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by
other utilities. In August 2000, in an appeal of related cases involving other
unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard contract between utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court. On January 17,
2003, the U.S. Court of Federal Claims ruled in our favor on the issue of
liability. The case continued on the issue of damages owed to us by the DOE. In
May 2004, the U.S. Court of Federal Claims ruled against us and denied damages.
In July 2004, we appealed this ruling to the U.S. Court of Appeals for the
Federal Circuit. As long as the delay in the availability of the government
approved storage repository for SNF continues, the cost of both temporary and
permanent storage of SNF and the cost of decommissioning will continue to
increase. If such cost increases are not recovered on a timely basis in
regulated rates, future results of operations and cash flows could be adversely
affected.
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $41,995
(Gain) Loss from Contracts Realized/Settled During the Period (a) (15,341)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) (222)
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) 2,215
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) (761)
--------
Total MTM Risk Management Contract Net Assets 27,886
Net Cash Flow Hedge Contracts (f) (13,236)
DETM Assignment (g) (16,583)
--------
Total MTM Risk Management Contract Net Liabilities at September 30, 2004 $(1,933)
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts that were entered into in 2004.
(d) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather, etc.
(e) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss). (g) See Note 17 "Related
Party Transactions" in the 2003 Annual Report.
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of September 30, 2004
MTM Risk
Management Cash Flow DETM
Contracts (a) Hedges Assignment (b) Consolidated (c)
------------- --------- -------------- ----------------
(in thousands)
Current Assets $56,305 $696 $- $57,001
Non Current Assets 52,232 133 - 52,365
-------- --------- --------- ---------
Total MTM Derivative
Contract Assets 108,537 829 - 109,366
-------- --------- --------- ---------
Current Liabilities (51,645) (12,998) (6,833) (71,476)
Non Current Liabilities (29,006) (1,067) (9,750) (39,823)
-------- --------- --------- ---------
Total MTM Derivative
Contract Liabilities (80,651) (14,065) (16,583) (111,299)
-------- --------- --------- ---------
Total MTM Derivative
Contract Net Assets
(Liabilities) $27,886 $(13,236) $(16,583) $(1,933)
======== ========= ========= =========
(a) Does not include Cash Flow Hedges.
(b) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
(c) Represents amount of total MTM derivative contracts recorded within
Risk Management Assets, Long-term Risk Management Assets, Risk
Management Liabilities and Long-term Risk Management Liabilities on our
Consolidated Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 (c) Total (d)
--------- ---- ---- ---- ---- -------- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $1,402 $(4,196) $18 $1,329 $- $- $(1,447)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (1,752) 7,967 2,120 1,348 - - 9,683
Prices Based on Models and Other
Valuation Methods (b) 441 2,056 2,721 2,269 3,752 8,411 19,650
------- -------- ------- ------- ------- ------- --------
Total $91 $5,827 $4,859 $4,946 $3,752 $8,411 $27,886
======= ======== ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over-the-counter brokers, industry services, or
multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources. Modeled information is
derived using valuation models developed by the reporting entity,
reflecting when appropriate, option pricing theory, discounted cash flow
concepts, valuation adjustments, etc. and may require projection of
prices for underlying commodities beyond the period that prices are
available from third-party sources. In addition, where external pricing
information or market liquidity are limited, such valuations are
classified as modeled. The determination of the point at which a market
is no longer liquid for placing it in the modeled category varies by
market.
(c) There is mark-to-market value in excess of 10 percent of our total
mark-to-market value in individual periods beyond 2008. $3.8 million of
this mark-to-market value is in 2009 and $3.7 million of this mark-to-market
is in 2010.
(d) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
Interest
Power Rate Consolidated
----- -------- ------------
(in thousands)
Beginning Balance December 31, 2003 $222 $- $222
Changes in Fair Value (a) (1,650) (6,188) (7,838)
Reclassifications from AOCI to Net Income (b) (927) - (927)
-------- -------- --------
Ending Balance September 30, 2004 $(2,355) $(6,188) $(8,543)
======== ======== ========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $2,393 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
--------------------------- --------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$196 $1,087 $505 $176 $368 $1,429 $598 $142
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates primarily related to long-term debt with fixed interest rates was
$89 million and $79 million at September 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
-------------------- --------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $372,558 $356,003 $1,065,830 $1,022,296
Sales to AEP Affiliates 70,378 67,001 193,048 196,212
--------- --------- ----------- -----------
TOTAL 442,936 423,004 1,258,878 1,218,508
--------- --------- ----------- -----------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 75,086 67,588 204,709 206,445
Purchased Electricity for Resale 10,063 9,058 22,617 22,375
Purchased Electricity from AEP Affiliates 74,498 68,653 203,291 207,904
Other Operation 100,537 109,106 306,187 319,019
Maintenance 33,737 38,518 118,055 112,480
Depreciation and Amortization 43,170 43,453 128,581 130,020
Taxes Other Than Income Taxes 10,291 15,698 40,979 44,668
Income Taxes 28,072 14,688 67,169 41,136
--------- --------- ----------- -----------
TOTAL 375,454 366,762 1,091,588 1,084,047
--------- --------- ----------- -----------
OPERATING INCOME 67,482 56,242 167,290 134,461
Nonoperating Income 20,248 20,723 60,857 42,670
Nonoperating Expenses 20,754 19,518 52,936 50,395
Nonoperating Income Tax Expense (Credit) (953) 821 1,538 (4,479)
Interest Charges 16,381 19,510 52,087 64,603
--------- --------- ----------- -----------
Net Income Before Cumulative Effect of Accounting Change 51,548 37,116 121,586 66,612
Cumulative Effect of Accounting Change (Net of Tax) - - - (3,160)
--------- --------- ----------- -----------
NET INCOME 51,548 37,116 121,586 63,452
Preferred Stock Dividend Requirements (Including Capital
Stock Expense) 119 118 356 2,390
--------- --------- ----------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $51,429 $36,998 $121,230 $61,062
========= ========= =========== ===========
The common stock of I&M is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $56,584 $858,560 $143,996 $(40,487) $1,018,653
Common Stock Dividends (30,000) (30,000)
Preferred Stock Dividends (2,289) (2,289)
Capital Stock Expense 101 (101) -
-----------
986,364
-----------
COMPREHENSIVE INCOME
- ---------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges 821 821
NET INCOME 63,452 63,452
-----------
TOTAL COMPREHENSIVE INCOME 64,273
-------- --------- --------- --------- -----------
SEPTEMBER 30, 2003 $56,584 $858,661 $175,058 $(39,666) $1,050,637
======== ========= ========= ========= ===========
DECEMBER 31, 2003 $56,584 $858,694 $187,875 $(25,106) $1,078,047
Common Stock Dividends (79,293) (79,293)
Preferred Stock Dividends (255) (255)
Capital Stock Expense 107 (101) 6
-----------
998,505
-----------
COMPREHENSIVE INCOME
- ---------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (8,765) (8,765)
NET INCOME 121,586 121,586
-----------
TOTAL COMPREHENSIVE INCOME 112,821
-------- --------- --------- --------- -----------
SEPTEMBER 30, 2004 $56,584 $858,801 $229,812 $(33,871) $1,111,326
======== ========= ========= ========= ===========
See Notes to Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- --------------------------------------------------------
Production $2,963,158 $2,878,051
Transmission 1,005,455 1,000,926
Distribution 979,690 958,966
General (including nuclear fuel) 275,941 274,283
Construction Work in Progress 171,792 193,956
----------- ----------
TOTAL 5,396,036 5,306,182
Accumulated Depreciation and Amortization 2,579,039 2,490,912
----------- ----------
TOTAL - NET 2,816,997 2,815,270
----------- ----------
OTHER PROPERTY AND INVESTMENTS
- --------------------------------------------------------
Nuclear Decommissioning and Spent Nuclear Fuel
Disposal Trust Funds 1,029,112 982,394
Non-Utility Property, Net 50,480 52,303
Other Investments 29,499 43,797
----------- ----------
TOTAL 1,109,091 1,078,494
----------- ----------
CURRENT ASSETS
- --------------------------------------------------------
Cash and Cash Equivalents 2,381 3,899
Other Cash Deposits 46 15
Accounts Receivable:
Customers 52,841 63,084
Affiliated Companies 93,282 124,826
Miscellaneous 4,176 4,498
Allowance for Uncollectible Accounts (46) (531)
Fuel 31,350 33,968
Materials and Supplies 128,156 105,328
Risk Management Assets 57,001 44,071
Margin Deposits 3,529 7,245
Prepayments and Other 9,159 10,673
----------- ----------
TOTAL 381,875 397,076
----------- ----------
DEFERRED DEBITS AND OTHER ASSETS
- --------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 138,575 151,973
Incremental Nuclear Refueling Outage Expenses, Net 26,131 57,326
Other 69,489 66,978
Long-term Risk Management Assets 52,365 43,768
Deferred Property Taxes 11,896 21,916
Deferred Charges and Other Assets 35,674 26,270
----------- ----------
TOTAL 334,130 368,231
----------- ----------
TOTAL ASSETS $4,642,093 $4,659,071
=========== ==========
See Notes to Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- -----------------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $56,584 $56,584
Paid-in Capital 858,801 858,694
Retained Earnings 229,812 187,875
Accumulated Other Comprehensive Income (Loss) (33,871) (25,106)
----------- -----------
Total Common Shareholder's Equity 1,111,326 1,078,047
Cumulative Preferred Stock - Not Subject to Mandatory Redemption 8,084 8,101
----------- -----------
Total Shareholders' Equity 1,119,410 1,086,148
Liability for Cumulative Preferred Stock - Subject to Mandatory
Redemption 61,445 63,445
Long-term Debt 1,137,189 1,134,359
----------- -----------
TOTAL 2,318,044 2,283,952
----------- -----------
CURRENT LIABILITIES
- -----------------------------------------------------------
Long-term Debt Due Within One Year - 205,000
Advances from Affiliates 98,762 98,822
Accounts Payable:
General 88,262 101,776
Affiliated Companies 37,114 47,484
Customer Deposits 31,070 21,955
Taxes Accrued 97,266 42,189
Interest Accrued 20,705 17,963
Risk Management Liabilities 71,476 31,898
Obligations Under Capital Leases 5,984 6,528
Other 80,790 57,675
----------- -----------
TOTAL 531,429 631,290
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- -----------------------------------------------------------
Deferred Income Taxes 321,376 337,376
Regulatory Liabilities:
Asset Removal Costs 274,281 263,015
Deferred Investment Tax Credits 84,782 90,278
Excess ARO for Nuclear Decommissioning 232,569 215,715
Other 65,012 61,268
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 67,398 70,179
Long-term Risk Management Liabilities 39,823 33,537
Obligations Under Capital Leases 35,966 31,315
Asset Retirement Obligations 582,827 553,219
Deferred Credits and Other 88,586 87,927
----------- -----------
TOTAL 1,792,620 1,743,829
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $4,642,093 $4,659,071
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- -----------------------------------------------------
Net Income $121,586 $63,452
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change - 3,160
Depreciation and Amortization 128,581 130,020
Deferred Income Taxes 2,772 (17,767)
Deferred Investment Tax Credits (5,496) (5,504)
Deferred Property Taxes 10,020 9,930
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses, Net 31,195 (4,049)
Unrecovered Fuel and Purchased Power Costs 452 28,126
Amortization of Nuclear Outage Costs - 30,000
Mark-to-Market of Risk Management Contracts 10,760 30,661
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 41,624 68,914
Fuel, Materials and Supplies (20,210) (2,488)
Accounts Payable, Net (23,884) (95,624)
Customer Deposits 9,115 3,874
Taxes Accrued 55,077 (28,144)
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets (2,377) (34,012)
Change in Other Liabilities 29,490 (7,995)
--------- ---------
Net Cash Flows From Operating Activities 407,169 191,018
--------- ---------
INVESTING ACTIVITIES
- -----------------------------------------------------
Construction Expenditures (122,756) (108,201)
Other 874 1,655
Change in Other Cash Deposits, Net (31) (28)
--------- ---------
Net Cash Flows Used For Investing Activities (121,913) (106,574)
--------- ---------
FINANCING ACTIVITIES
- -----------------------------------------------------
Retirement of Cumulative Preferred Stock (2,011) (1,500)
Retirement of Long-term Debt - Nonaffiliated (205,155) (255,000)
Change in Advances to/from Affiliates, Net (60) 205,155
Dividends Paid on Common Stock (79,293) (30,000)
Dividends Paid on Cumulative Preferred Stock (255) (2,289)
--------- ---------
Net Cash Flows Used For Financing Activities (286,774) (83,634)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (1,518) 810
Cash and Cash Equivalents at Beginning of Period 3,899 3,251
--------- ---------
Cash and Cash Equivalents at End of Period $2,381 $4,061
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $46,694,000 and $59,359,000 and for income taxes was $(4,725,000)
and $79,880,000 in 2004 and 2003, respectively. Noncash acquisitions under capital leases were $5,303,000 in 2004. There were no
noncash capital lease acquisitions in 2003.
See Notes to Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to I&M's consolidated financial statements are combined with the notes
to financial statements for other subsidiary registrants. Listed below are the
notes that apply to I&M.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
KENTUCKY POWER COMPANY
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Net Income for the third quarter of 2004 decreased $341 thousand from the prior
year period as increased retail revenues were offset by increased Fuel for
Electric Generation expenses and decreased Nonoperating Income (Loss) due to
unfavorable risk management activities.
Net Income for the nine months ended September 30, 2004 increased $1 million
from the prior year period primarily due to the Cumulative Effect of Accounting
Change recorded in 2003.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income for the third quarter of 2004 increased slightly from the prior
year period primarily due to the following:
o A $7 million increase in Electric Generation, Transmission and Distribution
revenues primarily relating to increased retail revenues. The retail
revenues increased primarily due to an increase in industrial sales related
to improvements in the economy as well as the recovery of increased fuel
costs.
o A $3 million increase in Sales to AEP Affiliates relating to a 5% increase
in Rockport plant generation enabling us to sell additional power to
affiliates in comparison to the prior year period.
o A $2 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
The increase in Operating Income for the third quarter of 2004 compared to the
prior year period was partially offset by the following:
o A $10 million increase in Fuel for Electric Generation expenses
primarily resulting from an increase in the cost of coal consumed and an
unfavorable impact of recording a liability for over-collection of fuel
costs. This over-collection will be refunded to customers over the twelve
months beginning November 2004.
o A $2 million increase in Purchased Electricity from AEP Affiliates resulting
from purchases in accordance with the unit power agreement with AEGCo
reflecting the 5% increase in generation at the Rockport plant. Our energy
purchases from the Rockport plant are based on plant availability, as
required by the unit power agreement with AEGCo, an affiliated company. The
unit power agreement with AEGCo provides for our purchase of 15% of the
total output of the two unit 2,600 MW capacity Rockport plant.
Other Impacts on Earnings
- -------------------------
Nonoperating Income (Loss) decreased $1 million in the third quarter of 2004
compared to the prior year period primarily due to unfavorable results from risk
management activities.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 11.4% and
36.4%, 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, 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 and changes in flow-through temporary differences.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income for the nine months ended September 30, 2004 increased slightly
from the prior year period primarily due to:
o A $20 million increase in Electric Generation, Transmission and Distribution
revenues primarily related to increased retail revenues. The retail revenues
increased primarily due to an environmental surcharge increase in July 2003,
a 24% increase in cooling degree days, and an increase in industrial sales
due to the recovering economy.
o A $6 million decrease in Purchased Electricity from AEP Affiliates resulting
from a 19% increase in Big Sandy's generation in 2004 related to planned
outages in 2003 for the installation of emission control equipment. The
2004 increase in generation from the Big Sandy plant reduced our need to
purchase additional power from AEP affiliates.
o A $5 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
o A $3 million increase in Sales to AEP Affiliates reflecting recovery of
increased fuel expenses.
The increase in Operating Income for the nine months ended September 30, 2004
was partially offset by:
o A $23 million increase in Fuel for Electric Generation expenses resulting
from a 19% increase in generation for 2004 over 2003 and an increase in the
average cost per ton of fuel consumed in the same period. In addition, Fuel
for Electric Generation expense was unfavorably affected due to the impact
of recording a liability for over-collection of fuel costs. This over-
collection will be refunded over the twelve months beginning November 2004.
o A $4 million increase in Depreciation and Amortization expense in 2004
primarily resulting from the installation of emission control equipment
at the Big Sandy plant in mid-2003.
o A $3 million increase in Maintenance expenses relating to planned outages
for boiler overhauls in 2004.
o A $3 million increase in Other Operation expenses for 2004 relating to
increased administrative and support expenses.
Other Impacts on Earnings
- -------------------------
Nonoperating Income (Loss) increased $3 million in the nine months ended
September 30, 2004 compared to the prior year period primarily due to favorable
results from risk management activities.
Interest Charges increased $1 million in the nine months ended September 30,
2004 compared to the prior year period primarily due to reduced capitalized
interest as well as increased long-term debt outstanding.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were 27.4%
and 35.5%, 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, 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, changes in flow-through temporary differences, and lower
state income taxes.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
Senior Unsecured Debt Baa2 BBB BBB
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first nine months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Notes Payable - Affiliated $20,000 5.25 2015
Retirements
-----------
None
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $15,490
(Gain) Loss from Contracts Realized/Settled During the Period (a) (5,552)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) (81)
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) 686
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) (344)
--------
Total MTM Risk Management Contract Net Assets 10,199
Net Cash Flow Hedge Contracts (f) (409)
DETM Assignment (g) (6,051)
--------
Total MTM Risk Management Contract Net Assets at September 30, 2004 $3,739
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and
unexpired option contracts that were entered into in 2004.
(d) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
etc.
(e) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Statements of Income. These
net gains (losses) are recorded as regulatory liabilities/assets
for those subsidiaries that operate in regulated jurisdictions.
(f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(g) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
Reconciliation of MTM Risk Management Contracts to
Balance Sheets
As of September 30, 2004
MTM Risk
Management Cash Flow DETM
Contracts(a) Hedges Assignment(b) Total(c)
------------ --------- ------------- --------
(in thousands)
Current Assets $20,549 $996 $- $21,545
Non Current Assets 19,057 133 - 19,190
-------- ------- -------- --------
Total MTM Derivative Contract Assets 39,606 1,129 - 40,735
-------- ------- -------- --------
Current Liabilities (18,843) (1,207) (2,493) (22,543)
Non Current Liabilities (10,564) (331) (3,558) (14,453)
-------- ------- -------- --------
Total MTM Derivative Contract Liabilities (29,407) (1,538) (6,051) (36,996)
-------- ------- -------- --------
Total MTM Derivative Contract Net
Assets (Liabilities) $10,199 $(409) $(6,051) $3,739
======== ======= ======== ========
(a) Does not include Cash Flow Hedges.
(b) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
(c) Represents amount of total MTM derivative contracts recorded within
Risk Management Assets, Long-term Risk Management Assets, Risk
Management Liabilities and Long-term Risk Management Liabilities on
our Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2004
------------------------------------------------
Remainder After
2004 2005 2006 2007 2008 2008 (c) Total (d)
---- ---- ---- ---- ---- -------- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $512 $(1,531) $7 $485 $- $- $(527)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (709) 2,982 774 492 - - 3,539
Prices Based on Models and Other
Valuation Methods (b) 180 750 993 827 1,369 3,068 7,187
----- -------- ------- ------- ------- ------- --------
Total $(17) $2,201 $1,774 $1,804 $1,369 $3,068 $10,199
===== ======== ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over-the-counter brokers, industry services, or
multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources. Modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(c) There is mark-to-market value in excess of 10 percent of our total mark-
to-market value in individual periods beyond 2008. $1.4 million of this
mark-to-market value is in 2009 and $1.4 million of this mark-to-market
is in 2010.
(d) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
------------------------------------------------------------
Power Interest Rate Total
----- ------------- -----
(in thousands)
Beginning Balance December 31, 2003 $82 $338 $420
Changes in Fair Value (a) (618) - (618)
Reclassifications from AOCI to Net
Income (b) (322) (65) (387)
------ ----- -------
Ending Balance September 30, 2004 $(858) $273 $(585)
====== ===== =======
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the reporting
period not yet reclassified into net income, pending the hedged item's
affecting net income. Amounts are reported net of related income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that were
reclassified into net income during the reporting period. Amounts are
reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $590 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
-------------------------------------- -------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$71 $397 $184 $64 $136 $527 $220 $52
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates primarily related to long-term debt with fixed interest rates was
$25 million and $29 million at September 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or financial position.
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
-------------------- ---------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $100,393 $93,500 $301,328 $281,755
Sales to AEP Affiliates 13,111 10,193 32,096 29,496
---------- -------- -------- ---------
TOTAL 113,504 103,693 333,424 311,251
---------- -------- -------- ---------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 29,380 19,608 75,498 52,994
Purchased Electricity from AEP Affiliates 37,725 35,461 102,848 109,008
Other Operation 12,848 12,519 39,128 36,351
Maintenance 5,925 6,671 23,464 20,597
Depreciation and Amortization 11,004 10,693 32,768 28,653
Taxes Other Than Income Taxes 2,208 2,300 6,931 6,742
Income Taxes 935 3,344 8,489 13,011
---------- -------- -------- ---------
TOTAL 100,025 90,596 289,126 267,356
---------- -------- -------- ---------
OPERATING INCOME 13,479 13,097 44,298 43,895
Nonoperating Income (Loss) (137) 1,309 1,297 (1,636)
Nonoperating Expenses 168 192 1,755 554
Nonoperating Income Tax Expense (Credit) (144) 370 (238) (1,114)
Interest Charges 7,158 7,343 22,239 21,202
---------- -------- -------- ---------
Income Before Cumulative Effect of Accounting Change 6,160 6,501 21,839 21,617
Cumulative Effect of Accounting Change (Net of Tax) - - - (1,134)
---------- -------- -------- ---------
NET INCOME $6,160 $6,501 $21,839 $20,483
========== ======== ======== =========
The common stock of KPCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
KENTUCKY POWER COMPANY
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $50,450 $208,750 $48,269 $(9,451) $298,018
Common Stock Dividends (16,448) (16,448)
---------
TOTAL 281,570
---------
COMPREHENSIVE INCOME
- ------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges 235 235
NET INCOME 20,483 20,483
---------
TOTAL COMPREHENSIVE INCOME 20,718
-------- --------- -------- --------- ---------
SEPTEMBER 30, 2003 $50,450 $208,750 $52,304 $(9,216) $302,288
======== ========= ======== ========= =========
DECEMBER 31, 2003 $50,450 $208,750 $64,151 $(6,213) $317,138
Common Stock Dividends (16,000) (16,000)
---------
TOTAL 301,138
---------
COMPREHENSIVE INCOME
- ------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,005) (1,005)
NET INCOME 21,839 21,839
---------
TOTAL COMPREHENSIVE INCOME 20,834
-------- --------- -------- --------- ---------
SEPTEMBER 30, 2004 $50,450 $208,750 $69,990 $(7,218) $321,972
======== ========= ======== ========= =========
See Notes to Financial Statements of Registrant Subsidiaries.
KENTUCKY POWER COMPANY
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -----------------------------------------------------------
Production $461,980 $457,341
Transmission 384,401 381,354
Distribution 436,768 425,688
General 59,662 68,041
Construction Work in Progress 13,539 17,322
----------- -----------
TOTAL 1,356,350 1,349,746
Accumulated Depreciation and Amortization 395,216 381,876
----------- -----------
TOTAL - NET 961,134 967,870
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ------------------------------------------------------------
Non-Utility Property, Net 5,440 5,423
Other Investments 398 1,022
----------- -----------
TOTAL 5,838 6,445
----------- -----------
CURRENT ASSETS
- ------------------------------------------------------------
Cash and Cash Equivalents 642 863
Other Cash Deposits 12 23
Advances to Affiliates 37,779 -
Accounts Receivable:
Customers 18,426 21,177
Affiliated Companies 19,630 25,327
Accrued Unbilled Revenues 3,461 5,534
Miscellaneous 90 97
Allowance for Uncollectible Accounts (25) (736)
Fuel 6,873 9,481
Materials and Supplies 19,309 16,585
Risk Management Assets 21,545 16,200
Margin Deposits 1,277 2,660
Prepayments and Other 2,261 1,696
----------- -----------
TOTAL 131,280 98,907
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ------------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 103,749 99,828
Other Regulatory Assets 15,779 13,971
Long-term Risk Management Assets 19,190 16,134
Deferred Property Taxes 1,756 6,847
Other Deferred Charges 11,884 11,632
----------- -----------
TOTAL 152,358 148,412
----------- -----------
TOTAL ASSETS $1,250,610 $1,221,634
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
KENTUCKY POWER COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ---------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $50,450 $50,450
Paid-in Capital 208,750 208,750
Retained Earnings 69,990 64,151
Accumulated Other Comprehensive Income (Loss) (7,218) (6,213)
----------- -----------
Total Common Shareholder's Equity 321,972 317,138
----------- -----------
Long-term Debt:
Nonaffiliated 428,592 427,602
Affiliated 80,000 60,000
----------- -----------
Total Long-term Debt 508,592 487,602
----------- -----------
TOTAL 830,564 804,740
----------- -----------
CURRENT LIABILITIES
- ---------------------------------------------------------
Advances from Affiliates - 38,096
Accounts Payable:
General 28,198 22,802
Affiliated Companies 23,913 22,648
Customer Deposits 12,722 9,894
Taxes Accrued 11,341 7,329
Interest Accrued 9,074 6,915
Risk Management Liabilities 22,543 11,704
Obligations Under Capital Leases 1,618 1,743
Other 8,224 8,628
----------- -----------
TOTAL 117,633 129,759
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ---------------------------------------------------------
Deferred Income Taxes 222,036 212,121
Regulatory Liabilities:
Asset Removal Costs 27,403 26,140
Deferred Investment Tax Credits 7,078 7,955
Other Regulatory Liabilities 14,765 10,591
Long-term Risk Management Liabilities 14,453 12,363
Obligations Under Capital Leases 2,987 3,549
Deferred Credits and Other 13,691 14,416
----------- -----------
TOTAL 302,413 287,135
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $1,250,610 $1,221,634
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ---------------------------------------------------------------
Net Income $21,839 $20,483
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change - 1,134
Depreciation and Amortization 32,768 28,653
Deferred Income Taxes 6,536 16,020
Deferred Investment Tax Credits (877) (880)
Deferred Property Taxes 5,091 4,698
Deferred Fuel Costs, Net 1,886 (772)
Loss on Sale of Assets 1,062 -
Mark-to-Market of Risk Management Contracts 3,994 9,950
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 9,817 13,326
Fuel, Materials and Supplies (116) (613)
Accounts Payable, Net 6,661 (39,620)
Taxes Accrued 4,012 1,455
Change in Other Assets (6,344) (6,753)
Change in Other Liabilities 10,621 (61)
-------- --------
Net Cash Flows From Operating Activities 96,950 47,020
-------- --------
INVESTING ACTIVITIES
- ---------------------------------------------------------------
Construction Expenditures (26,845) (71,154)
Proceeds from Sales of Property and Other 1,538 967
Change in Other Cash Deposits, Net 11 (4)
-------- --------
Net Cash Flow Used for Investing Activities (25,296) (70,191)
-------- --------
FINANCING ACTIVITIES
- ---------------------------------------------------------------
Issuance of Long-term Debt - Affiliated 20,000 74,263
Retirement of Long-term Debt - Nonaffiliated - (40,000)
Retirement of Long-term Debt - Affiliated - (15,000)
Change in Advances to/from Affiliates, Net (75,875) 18,809
Dividends Paid (16,000) (16,448)
-------- --------
Net Cash Flows From (Used For) Financing Activities (71,875) 21,624
-------- --------
Net Decrease in Cash and Cash Equivalents (221) (1,547)
Cash and Cash Equivalents at Beginning of Period 863 2,285
-------- --------
Cash and Cash Equivalents at End of Period $642 $738
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $19,198,000 and $17,925,000 and for income taxes was $(3,233,000)
and $(7,605,000) in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries.
KENTUCKY POWER COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to KPCo's financial statements are combined with the notes to
financial statements for other subsidiary registrants. Listed below are the
notes that apply to KPCo.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
OHIO POWER COMPANY CONSOLIDATED
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income decreased $20 million for the quarter primarily due to an $11 million
decrease in retail revenues driven by lower residential and commercial sales and
a $9 million favorable adjustment recorded in September 2003 for decreased costs
associated with coal companies sold prior to 2003.
Net Income decreased $150 million year-to-date primarily due to a $125 million
Cumulative Effect of Accounting Changes in the first quarter of 2003. Income
Before Cumulative Effect decreased $25 million year-to-date primarily due to a
decrease in sales for resale.
Effective July 1, 2003, we consolidated JMG Funding, LP (JMG) as a result of the
implementation of FIN 46. We record depreciation, interest and other operating
expenses of JMG and eliminate JMG's revenues against our operating lease
expenses. While there was no effect to net income as a result of consolidation,
some individual income statement captions are affected.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income for the third quarter of 2004 decreased $13 million from the
prior year period due to:
o An $11 million decrease in retail sales resulting from decreased weather-
related demand from residential and commercial customers.
o A $9 million increase in Fuel for Electric Generation primarily due to a
12% increase in the cost of coal consumed and a $4 million favorable coal
survey adjustment recorded in September 2003.
o A $2 million increase in Purchased Electricity from AEP Affiliates due to a
9% increase in MWHs purchased as a result of forced generating unit outages.
o A $2 million increase in Maintenance due to increases in scheduled and
forced boiler, electric and steam plant maintenance partially offset by a
reduction in costs associated with maintaining overhead lines.
o A $4 million increase in Depreciation and Amortization primarily associated
with a greater depreciable base in 2004, including capitalized software
costs and the increased amortization of transition generation regulatory
assets due to normal operating adjustments.
The decrease in Operating Income for the third quarter of 2004 was partially
offset by:
o A $6 million increase in operating revenues related to risk management
activities.
o A $4 million decrease in Other Operation expense primarily due to gains on
disposition of allowances.
o A $7 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
Other Impacts of Earnings
- -------------------------
Nonoperating Income for the third quarter of 2004 increased $27 million from the
prior year period primarily due to:
o $36 million in sales of excess energy purchased from Dow at the Plaquemine,
Louisiana plant (see Note 5) including the effects of a related affiliate
agreement which eliminates our market exposure related to the purchases from
Dow. There was no change in overall net income due to the agreement with
Dow. These sales in 2004 were offset by a $9 million favorable adjustment
recorded in September 2003 for decreased costs associated with coal
companies sold prior to 2003.
Nonoperating Expenses for the third quarter of 2004 increased $43 million from
the prior year period primarily due to:
o $38 million from the agreement to purchase excess energy from Dow at the
Plaquemine, Louisiana plant (see Note 5). There was no change in overall
net income due to the agreement with Dow.
o $4 million of unfavorable risk management activities.
Nonoperating Income Tax Expense decreased $4 million. See Income Taxes section
below for further discussion.
Interest charges for the third quarter of 2004 decreased $5 million from the
prior year period primarily due to redemption of higher cost First Mortgage
Bonds and Senior Unsecured Notes replaced with Affiliated Notes Payable at lower
interest rates.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 32.3% and
33.3%, 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, amortization of investment tax
credits and state income taxes. The effective tax rates remained relatively flat
for the comparative period.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income for the nine months ended September 30, 2004 decreased $20
million compared to the prior year period due to:
o A $9 million decrease in non-affiliated wholesale energy sales due to a
lower sales volume.
o A $12 million decrease in non-affiliated system sales due to a 12% decrease
in MWHs sold.
o A $9 million decrease in Sales to AEP Affiliates. The decrease is
primarily the result of an 8.6% decrease in MWH for affiliated system
sales partially offset by a $5 million increase in capacity credit.
o A $7 million decrease in other operating revenue primarily due to the
expiration of a contract with Buckeye Power.
o A $14 million increase in Fuel for Electric Generation due to higher coal
cost.
o A $4 million increase in Maintenance due primarily to boiler overhaul work
from scheduled and forced outages and turbine repairs.
o A $25 million increase in Depreciation and Amortization primarily
associated with the consolidation of JMG. Depreciation expense
related to the assets owned by JMG were consolidated effective
July 1, 2003 (there was no change in overall net income due to the
consolidation of JMG). In addition, the increase is a result of a
greater depreciable base in 2004, including capitalized software
and the increased amortization of transition generation regulatory
assets due to normal operating adjustments.
The decrease in Operating Income for the nine months ended September 30, 2004
was partially offset by:
o A $6 million increase in retail electric revenues resulting from increased
demand from industrial customers.
o A $15 million increase in operating revenues related to favorable risk
management activities.
o An $11 million decrease in Purchased Electricity for Resale primarily due to
cessation of the Buckeye Transmission agreement on June 30, 2003. Prior to
this date, Ohio Edison interchange expenses were recorded in Purchased
Electricity for Resale. An associated offsetting decrease in Ohio Edison
revenue occurred in non affiliated sales for resale; therefore, there was
no effect to net income. In addition, the DOE Settlement Capacity Surcharge
was included in rates through April 30, 2003, which is no longer in effect
for 2004.
o A $29 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
Other Impacts of Earnings
- -------------------------
Nonoperating Income increased $95 million primarily due to sales of excess
energy purchased from Dow at the Plaquemine, Louisiana plant (see Note 5)
including the effects of a related affiliate agreement which eliminates our
market exposure related to the purchases from Dow. There was no change in
overall net income due to the agreement with Dow. In addition, income from
nonoperating risk management contributed to this increase.
Nonoperating Expense increased $82 million primarily due to the agreement to
purchase excess energy from Dow at the Plaquemine, Louisiana plant (see Note 5).
There was no change in overall net income due to the agreement with Dow.
Interest charges increased $17 million primarily due to the consolidation of JMG
and its associated debt along with issuance of additional long-term debt in July
2003. There was no change in overall net income due to the consolidation of JMG.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were 34.3%
and 37.5%, 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, amortization of investment tax
credits and state income taxes. The decrease in the effective tax rate is
primarily due to lower state income taxes and federal income tax return
adjustments.
Cumulative Effect of Accounting Changes
- ---------------------------------------
The Cumulative Effect of Accounting Changes during 2003 of $125 million was due
to the one-time after-tax impact of adopting SFAS 143 and implementing the
requirements of EITF 02-3.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
Senior Unsecured Debt A3 BBB BBB+
Cash Flow
- ---------
Cash flows for the nine months ended September 30, 2004 and 2003 were as
follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $7,233 $5,275
--------- ---------
Cash flows from (used for):
Operating activities 447,996 225,658
Investing activities (151,809) (160,295)
Financing activities (299,977) (63,986)
--------- ---------
Net increase (decrease) in cash and cash equivalents
(3,790) 1,377
--------- ---------
Cash and cash equivalents at end of period $3,443 $6,652
========= =========
Operating Activities
- --------------------
Cash Flows From Operating Activities for the nine months ended September 30,
2004 increased $222 million compared to the prior year period. This is primarily
due to significant reductions in Accounts Payable balances during the second
quarter of 2003 partially associated with a wind-down of risk management
activities in that year.
Investing Activities
- --------------------
Cash Flows Used For Investing Activities were $152 million during the nine
months ended September 30, 2004 primarily due to new expenditures for
Generation, Transmission, Distribution and Environmental offset by a Change in
Other Cash Deposits, Net primarily as a result of monies set aside in 2003 for
the retirement of Installment Purchase Contracts in 2004. For the remainder of
2004, we expect our Construction Expenditures to be approximately $107 million.
Financing Activities
- --------------------
Cash Flows For Financing Activities used $300 million in the nine months ended
September 30, 2004 and $64 million in the prior year period. This is primarily
due to a decrease in the change in Advances to/from Affiliates, Net, during 2004
as a result of becoming a net lender as opposed to a net borrower.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the nine months ended September
30, 2004 were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- --------- ----
(in thousands) (%)
Notes Payable - Affiliates $200,000 5.25 2015
Notes Payable - Affiliates 200,000 3.32 2006
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- --------- ----
(in thousands) (%)
Installment Purchase Contracts $50,000 6.85 2022
Notes Payable 3,000 6.27 2009
Notes Payable 4,390 6.81 2008
First Mortgage Bonds 10,000 7.30 2024
Senior Unsecured Notes 140,000 7.375 2038
Senior Unsecured Notes 100,000 6.75 2004
Senior Unsecured Notes 75,000 7.00 2004
Other
- -----
Power Generation Facility
- -------------------------
AEP has 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 AEP. AEP has
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.
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 OPCo separately filed declaratory judgment actions
in the United States District Court for the Southern District of New York. OPCo
alleges that TEM has breached the PPA, and is seeking a determination of OPCo's
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 OPCo's
breaches. If the PPA is deemed terminated or found to be unenforceable by the
court, OPCo could be adversely affected to the extent it is unable to find other
purchasers of the power with similar contractual terms and to the extent OPCo
does not fully recover claimed termination value damages from TEM. However, OPCo
has entered into an agreement with an affiliate that eliminates OPCo's market
exposure related to the PPA. 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 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 Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
- -------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
Roll-Forward of MTM Risk Management Contract Net Assets
- -------------------------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $53,938
(Gain) Loss from Contracts Realized/Settled During the Period (a) (25,715)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) (277)
Change in Fair Value Due to Valuation Methodology Changes (d) 1,189
Changes in Fair Value of Risk Management Contracts (e) 9,825
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f) -
--------
Total MTM Risk Management Contract Net Assets 38,960
Net Cash Flow Hedge Contracts (g) (4,744)
DETM Assignment (h) (20,709)
--------
Total MTM Risk Management Contracts Net Assets at September 30, 2004 $13,507
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
storage, etc.
(f) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(h) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of September 30, 2004
MTM Risk
Management Cash Flow DETM
Contracts(a) Hedges Assignment(b) Consolidated (c)
------------ --------- ------------- ----------------
(in thousands)
Current Assets $80,477 $1,282 $- $81,759
Non Current Assets 68,558 452 - 69,010
--------- -------- --------- ---------
Total MTM Derivative Contract
Assets 149,035 1,734 - 150,769
--------- -------- --------- ---------
Current Liabilities (71,669) (5,329) (8,534) (85,532)
Non Current Liabilities (38,406) (1,149) (12,175) (51,730)
--------- -------- --------- ---------
Total MTM Derivative Contract
Liabilities (110,075) (6,478) (20,709) (137,262)
--------- -------- --------- ---------
Total MTM Derivative Contract Net
Assets (Liabilities) $38,960 $(4,744) $(20,709) $13,507
========= ======== ========= =========
(a) Does not include Cash Flow Hedges.
(b) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
(c) Represents amount of total MTM derivative contracts recorded within
Risk Management Assets, Long-term Risk Management Assets, Risk
Management Liabilities and Long-term Risk Management Liabilities on
our Consolidated Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 (c) Total (d)
---- ---- ---- ---- ---- -------- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $1,751 $(5,240) $22 $1,660 $- $- $(1,807)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (2,174) 13,544 2,869 2,243 - - 16,482
Prices Based on Models and Other
Valuation Methods (b) 630 2,168 3,506 2,794 4,685 10,502 24,285
------- -------- ------- ------- ------- -------- --------
Total $207 $10,472 $6,397 $6,697 $4,685 $10,502 $38,960
======= ======== ======= ======= ======= ======== ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources. Modeled information is
derived using valuation models developed by the reporting entity,
reflecting when appropriate, option pricing theory, discounted cash
flow concepts, valuation adjustments, etc. and may require projection
of prices for underlying commodities beyond the period that prices are
available from third-party sources. In addition, where external pricing
information or market liquidity are limited, such valuations are
classified as modeled. The determination of the point at which a market
is no longer liquid for placing it in the modeled category varies by
market.
(c) There is mark-to-market value in excess of 10 percent of our total
mark-to-market value in individual periods beyond 2008. $4.8 million of
this mark-to-market value is in 2009 and $4.6 million of this
mark-to-market is in 2010.
(d) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, economic hedge contracts which are not
designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
Foreign
Power Currency Consolidated
----- -------- ------------
(in thousands)
Beginning Balance December 31, 2003 $268 $(371) $(103)
Changes in Fair Value (a) (2,270) - (2,270)
Reclassifications from AOCI to Net
Income (b) (1,120) 10 (1,110)
-------- ------ --------
Ending Balance September 30, 2004 $(3,122) $(361) $(3,483)
======== ====== ========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $2,683 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
-------------------------------------- ------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$244 $1,357 $631 $220 $444 $1,724 $722 $172
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates primarily related to long-term debt with fixed interest rates was
$167 million and $214 million at September 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period; therefore, a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
-------------------- --------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $410,514 $418,083 $1,251,377 $1,256,862
Sales to AEP Affiliates 147,602 147,235 429,503 438,473
--------- --------- ----------- -----------
TOTAL 558,116 565,318 1,680,880 1,695,335
--------- --------- ----------- -----------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 164,353 155,222 476,127 462,316
Purchased Electricity for Resale 14,456 15,219 40,794 52,064
Purchased Electricity from AEP Affiliates 26,007 23,693 68,479 70,905
Other Operation 87,981 92,376 272,900 269,998
Maintenance 41,047 38,598 131,831 127,466
Depreciation and Amortization 71,857 67,365 214,027 189,140
Taxes Other Than Income Taxes 44,681 45,582 135,517 132,350
Income Taxes 26,897 33,465 89,099 118,597
--------- --------- ----------- -----------
TOTAL 477,279 471,520 1,428,774 1,422,836
--------- --------- ----------- -----------
OPERATING INCOME 80,837 93,798 252,106 272,499
Nonoperating Income 46,362 19,255 116,174 21,354
Nonoperating Expenses 50,809 7,528 108,109 26,569
Nonoperating Income Tax Expense (Credit) (2,660) 1,646 (693) (1,446)
Interest Charges 28,365 33,512 91,232 73,736
--------- --------- ----------- -----------
Income Before Cumulative Effect of Accounting Changes 50,685 70,367 169,632 194,994
Cumulative Effect of Accounting Changes (Net of Tax) - - - 124,632
--------- --------- ----------- -----------
NET INCOME 50,685 70,367 169,632 319,626
Preferred Stock Dividend Requirements 184 286 550 915
--------- --------- ----------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $50,501 $70,081 $169,082 $318,711
========= ========= =========== ===========
The common stock of OPCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ------------------ -----
DECEMBER 31, 2002 $321,201 $462,483 $522,316 $(72,886) $1,233,114
Common Stock Dividends (125,800) (125,800)
Preferred Stock Dividends (915) (915)
Capital Stock Gains 1 1
-----------
TOTAL 1,106,400
-----------
COMPREHENSIVE INCOME
- ----------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges 1,016 1,016
Minimum Pension Liability 5,625 5,625
NET INCOME 319,626 319,626
-----------
TOTAL COMPREHENSIVE INCOME 326,267
--------- --------- --------- ---------- -----------
SEPTEMBER 30, 2003 $321,201 $462,484 $715,227 $(66,245) $1,432,667
========= ========= ========= ========== ===========
DECEMBER 31, 2003 $321,201 $462,484 $729,147 $(48,807) $1,464,025
Common Stock Dividends (144,114) (144,114)
Preferred Stock Dividends (550) (550)
-----------
TOTAL 1,319,361
-----------
COMPREHENSIVE INCOME
- ----------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (3,380) (3,380)
Minimum Pension Liability (3,942) (3,942)
NET INCOME 169,632 169,632
-----------
TOTAL COMPREHENSIVE INCOME 162,310
--------- --------- --------- ---------- -----------
SEPTEMBER 30, 2004 $321,201 $462,484 $754,115 $(56,129) $1,481,671
========= ========= ========= ========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- --------------------------------------------------------------
Production $4,102,622 $4,029,515
Transmission 969,848 938,805
Distribution 1,191,189 1,156,886
General 251,720 245,434
Construction Work in Progress 162,450 142,951
----------- -----------
Total 6,677,829 6,513,591
Accumulated Depreciation and Amortization 2,582,823 2,485,947
----------- -----------
TOTAL - NET 4,095,006 4,027,644
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- --------------------------------------------------------------
Non-Utility Property, Net 45,788 47,015
Other 58,550 24,264
----------- -----------
TOTAL 104,338 71,279
----------- -----------
CURRENT ASSETS
- --------------------------------------------------------------
Cash and Cash Equivalents 3,443 7,233
Other Cash Deposits 50 51,017
Advances to Affiliates 232,212 67,918
Accounts Receivable:
Customers 99,840 100,960
Affiliated Companies 112,234 120,532
Accrued Unbilled Revenues 8,597 17,221
Miscellaneous 679 736
Allowance for Uncollectible Accounts (581) (789)
Fuel 81,785 77,725
Materials and Supplies 97,480 92,136
Risk Management Assets 81,759 56,265
Margin Deposits 4,962 9,296
Prepayments and Other 15,520 15,883
----------- -----------
TOTAL 737,980 616,133
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- --------------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 171,328 169,605
Transition Regulatory Assets 246,472 310,035
Unamortized Loss on Reacquired Debt 11,225 10,172
Other 24,101 22,506
Long-term Risk Management Assets 69,010 52,825
Deferred Property Taxes 20,665 67,469
Deferred Charges and Other Assets 38,951 26,850
----------- -----------
TOTAL 581,752 659,462
----------- -----------
TOTAL ASSETS $5,519,076 $5,374,518
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ------------------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $321,201 $321,201
Paid-in Capital 462,484 462,484
Retained Earnings 754,115 729,147
Accumulated Other Comprehensive Income (Loss) (56,129) (48,807)
----------- -----------
Total Common Shareholder's Equity 1,481,671 1,464,025
Cumulative Preferred Stock Not Subject to Mandatory Redemption 16,644 16,645
----------- -----------
Total Shareholders' Equity 1,498,315 1,480,670
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption 5,000 7,250
Long-term Debt:
Nonaffiliated 1,600,056 1,608,086
Affiliated 400,000 -
----------- -----------
Total Long-term Debt 2,000,056 1,608,086
----------- -----------
TOTAL 3,503,371 3,096,006
----------- -----------
Minority Interest 14,676 16,314
----------- -----------
CURRENT LIABILITIES
- ------------------------------------------------------------------------
Short-term Debt - General 19,562 25,941
Long-term Debt Due Within One Year - Nonaffiliated 60,354 431,854
Accounts Payable:
General 119,404 104,874
Affiliated Companies 90,555 101,758
Customer Deposits 27,908 17,308
Taxes Accrued 184,503 132,793
Interest Accrued 26,339 45,679
Risk Management Liabilities 85,532 38,318
Obligations Under Capital Leases 8,760 9,624
Other 71,807 71,642
----------- -----------
TOTAL 694,724 979,791
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ------------------------------------------------------------------------
Deferred Income Taxes 933,443 933,582
Regulatory Liabilities:
Asset Removal Costs 104,974 101,160
Deferred Investment Tax Credits 13,357 15,641
Other - 3
Long-term Risk Management Liabilities 51,730 40,477
Deferred Credits 26,225 23,222
Obligations Under Capital Leases 32,899 25,064
Asset Retirement Obligations 45,204 42,656
Other 98,473 100,602
----------- -----------
TOTAL 1,306,305 1,282,407
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $5,519,076 $5,374,518
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------------
Net Income $169,632 $319,626
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (124,632)
Depreciation and Amortization 214,027 189,140
Deferred Income Taxes 2,080 4,139
Deferred Investment Tax Credits (2,283) (2,288)
Deferred Property Taxes 46,804 46,491
Mark-to-Market of Risk Management Contracts 11,632 40,283
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 17,891 37,799
Fuel, Materials and Supplies (9,404) 4,515
Prepayments and Other Current Assets 4,697 (9,030)
Accounts Payable, Net 3,327 (215,012)
Customer Deposits 10,600 3,579
Taxes Accrued 51,710 (17,682)
Interest Accrued (19,340) 9,516
Change in Other Assets (51,835) (2,859)
Change in Other Liabilities (1,542) (57,927)
--------- ---------
Net Cash Flows From Operating Activities 447,996 225,658
--------- ---------
INVESTING ACTIVITIES
- ------------------------------------------------------------
Construction Expenditures (205,752) (163,864)
Change in Other Cash Deposits, Net 50,967 (51)
Proceeds from Sale of Property and Other 2,976 3,620
--------- ---------
Net Cash Flows Used For Investing Activities (151,809) (160,295)
--------- ---------
FINANCING ACTIVITIES
- ------------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated - 938,914
Issuance of Long-term Debt - Affiliated 400,000 -
Change in Advances to/from Affiliates, Net (164,294) (272,872)
Change in Short-term Debt, Net (6,379) 2,039
Change in Short-term Debt - Affiliates, Net - (275,000)
Retirement of Long-term Debt - Nonaffiliated (382,390) (29,850)
Retirement of Long-term Debt - Affiliated - (300,000)
Retirement of Cumulative Preferred Stock (2,250) (502)
Dividends Paid on Common Stock (144,114) (125,800)
Dividends Paid on Cumulative Preferred Stock (550) (915)
--------- ---------
Net Cash Flows Used For Financing Activities (299,977) (63,986)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (3,790) 1,377
Cash and Cash Equivalents at Beginning of Period 7,233 5,275
--------- ---------
Cash and Cash Equivalents at End of Period $3,443 $6,652
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $107,177,000 and $57,517,000 and for income taxes was
$(21,600,000) and $74,858,000 in 2004 and 2003, respectively. Noncash acquisitions under capital leases were $12,749,000 in 2004.
There were no noncash capital lease acquisitions in 2003.
See Notes to Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to OPCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below are
the notes that apply to OPCo.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
PUBLIC SERVICE COMPANY OF OKLAHOMA
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Net Income for the nine months ended September 30, 2004 decreased $19 million
from the prior year period due to increased operations and maintenance expenses
for power plant maintenance, transmission and tree trimming. Net Income
increased $1 million for the third quarter.
Fluctuations occurring in the retail portion of fuel and purchased power expense
generally do not impact operating income, as they are offset in revenues due to
the functioning of the fuel clause adjustment in Oklahoma.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income for the third quarter of 2004 increased $4 million from the
prior year period primarily due to:
o A $9 million increase in system sales margins.
o A $1 million decrease in Maintenance expenses primarily due to lower power
plant expenses.
The increase in Operating Income for the third quarter of 2004 was partially
offset by:
o A $4 million decrease in retail base revenue primarily due to a 19% decrease
in cooling degree-days.
o A $3 million increase in Other Operation expenses primarily due to customer
related expenses and administrative and general expenses.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $6 million in the third quarter of 2004 compared
to the prior year period primarily due to a gain on the disposition of land
recorded in 2003.
Interest Charges decreased $2 million in the third quarter of 2004 compared to
the prior year period due to reduced interest rates from refinancing higher cost
debt.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 37.6% and
40.5%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower state income taxes.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income for the nine months ended September 30, 2004 in comparison to
the prior year period decreased $20 million primarily due to:
o A $20 million increase in Other Operation expenses. Transmission expense
increased $9 million primarily related to prior years true-up for OATT
transmission recorded in 2004 resulting from revised data from ERCOT for the
years 2001-2003. Distribution expenses increased $5 million resulting mainly
from a labor settlement and various inventory and tracking system upgrades.
o A $13 million increase in Maintenance expenses primarily due to increased
power plant maintenance and tree trimming along with increased repairs of
storm damage.
o A $3 million decrease in transmission revenues primarily due to non-
affiliated transactions.
o A $1 million increase in Taxes Other Than Income Taxes primarily due to
increased property taxes attributable to changes in property values
and employee-related taxes offset in part by lower franchise taxes.
The decrease in Operating Income for the nine months ended September 30, 2004
was partially offset by:
o A $4 million increase in system sales margins due to the end of merger
related mitigation sales losses in 2003.
o A $4 million increase in retail base revenue primarily due to increased KWH
sales of 3%. Customer usage increased primarily from our industrial class
and number of customers offset in part by a decrease in heating and cooling
degree-days of 13%.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $6 million in the nine months ended September 30,
2004 compared to the prior year period primarily due to a gain on the
disposition of land recorded in 2003.
Interest Charges decreased $7 million in the nine months ended September 30,
2004 compared to the prior year period due to reduced interest rates from
refinancing higher cost debt.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were 32.2%
and 34.1%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 A- A
Senior Unsecured Debt Baa1 BBB A-
In July 2004, Standard and Poor's upgraded the credit rating of the First
Mortgage Bonds from BBB to A- due to a change in rating methodology. The
principal amount of First Mortgage Bonds currently outstanding is $100 million.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first nine months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase Contracts $33,700 Variable 2014
Senior Unsecured Notes 50,000 4.70 2009
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Notes Payable to Trust $77,320 8.00 2037
Installment Purchase Contracts 33,700 4.875 2014
Installment Purchase Contracts 1,000 5.90 2007
Significant Factors
- -------------------
Oklahoma Regulatory Activity
- ----------------------------
We 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 our 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, we 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. We filed our 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 unrecovered fuel and purchased power costs should not be recovered, there
will be, subject to the FERC jurisdictional question, an adverse effect on
results of operations, cash flows and possibly financial condition.
In February 2003, the OCC filed an application requiring us to file all
documents necessary for a general rate review. In October 2003 and June 2004, we
filed financial information and supporting testimony in response to the OCC's
requirements. The response indicates that annual revenues are $41 million less
than costs. As a result, we are seeking OCC approval to increase base rates by
that amount, which is a 3.9% increase over existing revenues. A decision is not
expected until second quarter 2005. Management is unable to predict the ultimate
effect of these proceedings on revenues, results of operations, cash flows and
financial condition.
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of other factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $14,057
(Gain) Loss from Contracts Realized/Settled During the Period (a) (980)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) (149)
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) -
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) (2,905)
--------
Total MTM Risk Management Contract Net Assets 10,023
Net Cash Flow Hedge Contracts (f) (3,588)
--------
Total MTM Risk Management Contract Net Assets at September 30, 2004 $6,435
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the Period"
represents the fair value of long-term contracts entered into with
customers during 2004. The fair value is calculated as of the execution
of the contract. Most of the fair value comes from longer term fixed
price contracts with customers that seek to limit their risk against
fluctuating energy prices. The contract prices are valued against
market curves associated with the delivery location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option premiums
paid/(received) as they relate to unexercised and unexpired option
contracts that were entered into in 2004.
(d) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
storage, etc.
(e) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Statements of Income. These net
gains (losses) are recorded as regulatory liabilities/assets for those
subsidiaries that operate in regulated jurisdictions.
(f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
Reconciliation of MTM Risk Management Contracts to
Balance Sheets
As of September 30, 2004
MTM Risk
Management Cash Flow
Contracts(a) Hedges Total (b)
------------ --------- ---------
(in thousands)
Current Assets $22,508 $293 $22,801
Non Current Assets 12,749 89 12,838
-------- -------- --------
Total MTM Derivative Contract
Assets 35,257 382 35,639
-------- -------- --------
Current Liabilities (19,258) (3,361) (22,619)
Non Current Liabilities (5,976) (609) (6,585)
-------- -------- --------
Total MTM Derivative Contract
Liabilities (25,234) (3,970) (29,204)
-------- -------- --------
Total MTM Derivative Contract Net
Assets (Liabilities) $10,023 $(3,588) $6,435
======== ======== ========
(a) Does not include Cash Flow Hedges.
(b) Represents amount of total MTM derivative contracts recorded within
Risk Management Assets, Long-term Risk Management Assets, Risk
Management Liabilities and Long-term Risk Management Liabilities on
our Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2004
-------------------------------------------------
Remainder After
2004 2005 2006 2007 2008 2008 (c) Total (d)
---- ---- ---- ---- ---- -------- ---------
(in thousands)
Prices Actively Quoted -
Exchange Traded Contracts $940 $(2,814) $12 $891 $- $- $(971)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (1,909) 6,566 586 - - - 5,243
Prices Based on Models and Other
Valuation Methods (b) 2 1,357 283 (75) 1,023 3,161 5,751
------- -------- ----- ----- ------- ------- --------
Total $(967) $5,109 $881 $816 $1,023 $3,161 $10,023
======= ======== ===== ===== ======= ======= ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources. Modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(c) There is mark-to-market value in excess of 10 percent of our total mark-
to-market value in individual periods beyond 2008. $1.2 million of this
mark-to-market value is in 2009.
(d) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, economic hedge contracts which are not
designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
Power Interest Rate Consolidated
----- ------------- ------------
(in thousands)
Beginning Balance December 31, 2003 $156 $- $156
Changes in Fair Value (a) (1,462) - (1,462)
Reclassifications from AOCI to Net
Income (b) (274) (743) (1,017)
-------- ------ --------
Ending Balance September 30, 2004 $(1,580) $(743) $(2,323)
======== ====== ========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,298 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
--------------------------------------- -------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$131 $729 $339 $118 $258 $1,004 $420 $100
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates primarily related to long-term debt with fixed interest rates was
$35 million and $66 million at September 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or financial position.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
-------------------- -------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $355,260 $355,064 $787,956 $860,544
Sales to AEP Affiliates 1,371 3,511 7,467 17,929
--------- --------- --------- ---------
TOTAL 356,631 358,575 795,423 878,473
--------- --------- --------- ---------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 139,712 177,162 315,803 415,731
Purchased Electricity for Resale 41,059 11,524 55,810 30,878
Purchased Electricity from AEP Affiliates 24,083 24,132 79,182 94,515
Other Operation 36,882 33,765 117,045 97,067
Maintenance 11,777 12,763 47,774 34,523
Depreciation and Amortization 22,762 21,715 67,097 64,568
Taxes Other Than Income Taxes 9,483 9,526 29,027 27,611
Income Taxes 23,671 24,461 18,767 28,192
--------- --------- --------- ---------
TOTAL 309,429 315,048 730,505 793,085
--------- --------- --------- ---------
OPERATING INCOME 47,202 43,527 64,918 85,388
Nonoperating Income 640 6,691 1,011 7,413
Nonoperating Expense 356 304 1,660 467
Nonoperating Income Tax Expense (Credit) (162) 1,488 (1,021) 1,133
Interest Charges 8,668 10,336 27,922 34,493
--------- --------- --------- ---------
NET INCOME 38,980 38,090 37,368 56,708
Preferred Stock Dividend Requirements 53 53 159 159
--------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $38,927 $38,037 $37,209 $56,549
========= ========= ========= =========
The common stock of PSO is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $157,230 $180,016 $116,474 $(54,473) $399,247
Capital Contribution from Parent 50,000 50,000
Common Stock Dividends (15,000) (15,000)
Preferred Stock Dividends (159) (159)
Distribution of Investment in AEMT, Inc.
Preferred Shares to Parent (548) (548)
---------
TOTAL 433,540
---------
COMPREHENSIVE INCOME
- --------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (59) (59)
Minimum Pension Liability 435 435
NET INCOME 56,708 56,708
---------
TOTAL COMPREHENSIVE INCOME 57,084
--------- --------- --------- --------- ---------
SEPTEMBER 30, 2003 $157,230 $230,016 $157,475 $(54,097) $490,624
========= ========= ========= ========= =========
DECEMBER 31, 2003 $157,230 $230,016 $139,604 $(43,842) $483,008
Common Stock Dividends (26,250) (26,250)
Preferred Stock Dividends (159) (159)
Gain on Reacquired Preferred Stock 2 2
---------
TOTAL 456,601
---------
COMPREHENSIVE INCOME
- --------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (2,479) (2,479)
NET INCOME 37,368 37,368
---------
TOTAL COMPREHENSIVE INCOME 34,889
--------- --------- --------- --------- ---------
SEPTEMBER 30, 2004 $157,230 $230,016 $150,565 $(46,321) $491,490
========= ========= ========= ========= =========
See Notes to Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ---------------------------------------------------------------
Production $1,070,014 $1,065,408
Transmission 455,065 458,577
Distribution 1,080,856 1,031,229
General 209,774 203,756
Construction Work in Progress 42,777 54,711
----------- -----------
TOTAL 2,858,486 2,813,681
Accumulated Depreciation and Amortization 1,111,748 1,069,216
----------- -----------
TOTAL - NET 1,746,738 1,744,465
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ---------------------------------------------------------------
Non-Utility Property, Net 4,402 4,631
Other Investments - 2,320
----------- -----------
TOTAL 4,402 6,951
----------- -----------
CURRENT ASSETS
- ---------------------------------------------------------------
Cash and Cash Equivalents 3,510 3,738
Other Cash Deposits - 10,520
Accounts Receivable:
Customers 26,953 28,515
Affiliated Companies 26,674 19,852
Miscellaneous 1,486 -
Allowance for Uncollectible Accounts (29) (37)
Fuel Inventory 17,788 18,331
Materials and Supplies 38,946 38,125
Regulatory Asset for Under-recovered Fuel Costs 26,044 24,170
Risk Management Assets 22,801 18,586
Margin Deposits 1,739 4,351
Prepayments and Other 2,073 2,655
----------- -----------
TOTAL 167,985 168,806
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ---------------------------------------------------------------
Regulatory Assets:
Unamortized Loss on Reacquired Debt 15,268 14,357
Other 17,557 14,342
Long-term Risk Management Assets 12,838 10,379
Deferred Charges 27,245 18,017
----------- -----------
TOTAL 72,908 57,095
----------- -----------
TOTAL ASSETS $1,992,033 $1,977,317
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- --------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued Shares: 10,482,000
Outstanding Shares: 9,013,000 $157,230 $157,230
Paid-in Capital 230,016 230,016
Retained Earnings 150,565 139,604
Accumulated Other Comprehensive Income (Loss) (46,321) (43,842)
----------- -----------
Total Common Shareholder's Equity 491,490 483,008
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,262 5,267
----------- -----------
Total Shareholders' Equity 496,752 488,275
Long-term Debt 446,057 490,598
----------- -----------
TOTAL 942,809 978,873
----------- -----------
CURRENT LIABILITIES
- --------------------------------------------------------------
Long-term Debt Due Within One Year 100,000 83,700
Advances from Affiliates 19,259 32,864
Accounts Payable:
General 58,650 48,808
Affiliated Companies 41,390 57,206
Customer Deposits 34,476 26,547
Taxes Accrued 54,520 27,157
Interest Accrued 3,633 3,706
Risk Management Liabilities 22,619 11,067
Obligations Under Capital Leases 478 452
Other 22,250 35,234
----------- -----------
TOTAL 357,275 326,741
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- --------------------------------------------------------------
Deferred Income Taxes 346,444 335,434
Long-Term Risk Management Liabilities 6,585 3,602
Regulatory Liabilities:
Asset Removal Costs 221,057 214,033
Deferred Investment Tax Credits 29,067 30,411
SFAS 109 Regulatory Liability, Net 23,112 24,937
Other 17,254 15,406
Obligations Under Capital Leases 597 558
Deferred Credits and Other 47,833 47,322
----------- -----------
TOTAL 691,949 671,703
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $1,992,033 $1,977,317
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- -----------------------------------------------------
Net Income $37,368 $56,708
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Depreciation and Amortization 67,097 64,568
Deferred Income Taxes 10,519 6,536
Deferred Investment Tax Credits (1,343) (1,343)
Deferred Property Taxes (8,648) (8,239)
Mark-to-Market of Risk Management Contracts 4,034 (9,783)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (6,754) (6,010)
Fuel, Materials and Supplies (278) 1,353
Accounts Payable, Net (5,974) 9,463
Taxes Accrued 27,363 12,342
Fuel Recovery (1,874) 32,862
Changes in Other Assets (12,326) (7,492)
Changes in Other Liabilities 4,447 12,430
--------- ---------
Net Cash Flows From Operating Activities 113,631 163,395
--------- ---------
INVESTING ACTIVITIES
- -----------------------------------------------------
Construction Expenditures (55,929) (59,263)
Proceeds from Sale of Property and Other 458 2,664
Change in Other Cash Deposits, Net 10,520 (2,916)
--------- ---------
Net Cash Flows Used For Investing Activities (44,951) (59,515)
--------- ---------
FINANCING ACTIVITIES
- -----------------------------------------------------
Capital Contributions from Parent - 50,000
Change in Advances to/from Affiliates, Net (13,605) (189,558)
Retirement of Long-term Debt (112,020) (100,000)
Issuance of Long-term Debt 83,129 148,734
Reacquired Preferred Stock (3) -
Dividends Paid on Common Stock (26,250) (15,000)
Dividends Paid on Cumulative Preferred Stock (159) (159)
--------- ---------
Net Cash Flows Used For Financing Activities (68,908) (105,983)
--------- ---------
Net Decrease in Cash and Cash Equivalents (228) (2,103)
Cash and Cash Equivalents at Beginning of Period 3,738 9,543
--------- ---------
Cash and Cash Equivalents at End of Period $3,510 $7,440
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $24,518,000 and $31,572,000 and for income taxes was $2,387,000 and
$33,658,000 in 2004 and 2003, respectively.
There was a non-cash distribution of $548,000 in preferred shares in AEMT, Inc. to PSO's Parent Company in 2003.
See Notes to Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to PSO's financial statements are combined with the notes to financial
statements for other subsidiary registrants. Listed below are the notes that
apply to PSO.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income decreased $2 million for 2004 year-to-date and increased $5 million
for the third quarter. The year-to-date decrease is primarily due to the $9
million (net of tax) Cumulative Effect of Accounting Changes recorded in 2003.
For the third quarter the increase is primarily due to favorable risk management
activities.
Fluctuations occurring in the retail portion of fuel and purchased power expense
generally do not impact operating income, as they are offset in revenues and/or
operations expense due to the functioning of the fuel adjustment clauses in the
states in which we serve.
Third Quarter 2004 Compared to Third Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income increased by $1 million primarily due to:
o A $4 million increase in margins from risk management activities.
o A $1 million increase in the portion of margin the company retains primarily
due to increased realization of off-system sales.
The increase in Operating Income was partially offset by:
o A $3 million increase in Other Operation expenses primarily due to
transmission expenses.
o A $3 million increase in Depreciation and Amortization expenses resulting
from the amortization of a regulatory asset for the recovery of fuel related
costs in Arkansas and adjustments to excess earnings accruals per the Texas
Legislation (see "Texas Restructuring" in Note 4).
o A $2 million increase in provision for rate refund primarily due to a
wholesale fuel refund.
Fuel and Purchased Power
- ------------------------
For the third quarter of 2004 compared to third quarter 2003, purchased power
expenses increased primarily due to an increase in KWH purchases of 35% and
a cost per KWH increase of 32%. Fuel expenses decreased 30% due to lower KWH
generation of 7% and lower cost per KWH of 14%. As discussed above, these items
have no impact on Operating Income.
Other Impacts on Earnings
- -------------------------
Interest Charges decreased $4 million as a result of refinancing higher interest
rate debt and notes payable to trust with lower interest rate debt and notes
payable to trust.
Income Taxes
- ------------
The effective tax rates for the third quarter of 2004 and 2003 were 32.8% and
36.3%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, 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 and permanent
differences relating to book depletion and Medicare subsidy.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- ------------------------------------------------------------------
Operating Income
- ----------------
Operating Income increased by $1 million primarily due to:
o An $11 million increase in retail base revenues due to an increased number
of customers and their average usage, offset in part by milder weather.
Heating and Cooling degree-days decreased 7%.
o A $9 million refund of capacity payments not recoverable through the fuel
clause for prior periods for purchased power.
The increase in Operating Income was partially offset by:
o A $10 million increase in Other Operation expenses primarily related to a
prior year true-up for OATT transmission recorded in 2004 resulting from
revised data from ERCOT for the years 2001-2003 offset in part by the sale
of emission allowances.
o An $8 million increase in Depreciation and Amortization expenses primarily
due to the amortization of a regulatory asset for the recovery of fuel
related costs in Arkansas and adjustments to excess earnings accruals per
the Texas Legislation (see "Texas Restructuring" in Note 4).
o A $7 million increase in Maintenance expenses primarily due to scheduled
power plant maintenance, as well as increased overhead line maintenance,
partly due to increased storm damage.
o A $5 million decrease in margins from risk management activities.
o A $4 million increase in provision for rate refund primarily due to a
wholesale fuel refund.
o A $3 million increase in Taxes Other Than Income Taxes primarily due to
higher property taxes and state and local franchise taxes.
o A $2 million decrease in the portion of margin the company retains from off-
system sales primarily due to decreased realization of off-system sales.
Fuel and Purchased Power
- ------------------------
For the nine month comparison, purchased power expense decreased primarily due
to KWH purchases declining 1%, the cost per KWH declining 2% and decreased
capacity purchases. Fuel expense also decreased 19% primarily due to lower KWH
generation of 6% and lower cost per KWH of 10%.
Other Impacts on Earnings
- -------------------------
Interest Charges decreased $7 million as a result of refinancing higher interest
rate debt and notes payable to trust with lower interest rate debt and notes
payable to trust.
Minority Interest loss of $2 million is a result of consolidating Sabine Mining
Company (Sabine) effective July 1, 2003, due to implementation of FIN 46. We now
record the depreciation, interest and other operating expenses of Sabine and
eliminate Sabine's revenues against our fuel expenses. While there was no effect
to net income as a result of consolidation, some individual income statement
lines were affected.
The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 and EITF 02-3 in 2003.
Income Taxes
- ------------
The effective tax rates for the first nine months of 2004 and 2003 were 31.4%
and 35.0%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, 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 and permanent
differences relating to book depletion and Medicare subsidy.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 A- A
Senior Unsecured Debt Baa1 BBB A-
In July 2004, Standard and Poor's upgraded the credit rating of the First
Mortgage Bonds from BBB to A- due to a change in rating methodology. The
principal amount of First Mortgage Bonds currently outstanding is $96 million.
Cash Flow
- ---------
Cash flows for the nine months ended September 30, 2004 and 2003 were as
follows:
2004 2003
---- ----
Cash and cash equivalents at beginning of period $5,676 $-
--------- ---------
Cash flows from (used for):
Operating activities 214,943 209,157
Investing activities (63,557) (81,126)
Financing activities (153,738) (117,234)
--------- ---------
Net increase (decrease) in cash and cash equivalents (2,352) 10,797
--------- ---------
Cash and cash equivalents at end of period $3,324 $10,797
========= =========
Operating Activities
- --------------------
Cash Flows From Operating Activities were $215 million primarily due to Net
Income, Fuel, Materials and Supplies, Fuel Recovery and Taxes Accrued offset in
part by Accounts Receivable, Net, Accounts Payable and Other Assets and
Liabilities.
Investing Activities
- --------------------
Cash Flows Used for Investing Activities were primarily for construction
projects for improved transmission and distribution service reliability. For the
remainder of 2004, we expect our Construction Expenditures to be approximately
$34 million.
Financing Activities
- --------------------
Cash Flows Used For Financing Activities were for retiring higher interest rate
long-term debt with lower interest rate long-term debt and advances from
affiliates.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first nine months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase Contracts $53,500 Variable 2019
Installment Purchase Contracts 41,135 Variable 2011
Notes Payable - Affiliates 50,000 4.45 2010
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase Contracts $53,500 7.60 2019
Installment Purchase Contracts 12,290 6.90 2004
Installment Purchase Contracts 12,170 6.00 2008
Installment Purchase Contracts 17,125 8.20 2011
First Mortgage Bonds 80,000 6.875 2025
First Mortgage Bonds 40,000 7.75 2004
Notes Payable 5,122 4.47 2011
Notes Payable 2,250 Variable 2008
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section for additional discussion of factors relevant to us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $16,606
(Gain) Loss from Contracts Realized/Settled During the Period (a) (4,354)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) (177)
Change in Fair Value Due to Valuation Methodology Changes (d) 62
Changes in Fair Value of Risk Management Contracts (e) 1,703
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f) (1,946)
--------
Total MTM Risk Management Contract Net Assets 11,894
Net Cash Flow Hedge Contracts (g) (6,621)
--------
Total MTM Risk Management Contract Net Assets at September 30, 2004 $5,273
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long- term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and
unexpired option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
etc.
(f) "Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of September 30, 2004
MTM Risk
Management Cash Flow
Contracts (a) Hedges Consolidated (b)
------------- --------- ----------------
(in thousands)
Current Assets $26,708 $348 $27,056
Non Current Assets 15,128 106 15,234
-------- -------- --------
Total MTM Derivative Contract
Assets 41,836 454 42,290
-------- -------- --------
Current Liabilities (22,851) (6,071) (28,922)
Non Current Liabilities (7,091) (1,004) (8,095)
-------- -------- --------
Total MTM Derivative Contract
Liabilities (29,942) (7,075) (37,017)
-------- -------- --------
Total MTM Derivative Contract Net
Assets (Liabilities) $11,894 $(6,621) $5,273
======== ======== ========
(a) Does not include Cash Flow Hedges.
(b) Represents amount of total MTM derivative contracts recorded
within Risk Management Assets, Long-term Risk Management Assets,
Risk Management Liabilities and Long-term Risk Management
Liabilities on our Consolidated Balance Sheets.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 (c) Total (d)
---- ---- ---- ---- ---- -------- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $1,116 $(3,340) $14 $1,058 $- $- $(1,152)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (2,265) 7,791 696 - - - 6,222
Prices Based on Models and Other
Valuation Methods (b) 2 1,610 336 (89) 1,214 3,751 6,824
-------- -------- ------- ------- ------- ------- --------
Total $(1,147) $6,061 $1,046 $969 $1,214 $3,751 $11,894
======== ======== ======= ======= ======= ======= ========
"Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over-the-counter brokers, industry services, or
multiple-party on-line platforms.
(a) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources. Modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(b) There is mark-to-market value in excess of 10 percent of our total
mark-to-market value in individual periods beyond 2008. $1.5
million of this mark-to-market value is in 2009.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2004
Power Interest Rate Consolidated
----- ------------- ------------
(in thousands)
Beginning Balance December 31, 2003 $184 $- $184
Changes in Fair Value (a) (1,735) - (1,735)
Reclassifications from AOCI to Net
Income (b) (323) (2,006) (2,329)
-------- -------- --------
Ending Balance September 30, 2004 $(1,874) $(2,006) $(3,880)
======== ======== ========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,519 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Nine Months Ended Twelve Months Ended
September 30, 2004 December 31, 2003
-------------------------------------- -------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$156 $865 $402 $140 $304 $1,182 $495 $118
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates primarily related to long-term debt with fixed interest rates was
$50 million and $57 million at September 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
Three Months Ended Nine Months Ended
-------------------- -------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $315,482 $347,672 $780,661 $835,193
Sales to AEP Affiliates 14,888 13,950 54,597 63,013
--------- --------- --------- ---------
TOTAL 330,370 361,622 835,258 898,206
--------- --------- --------- ---------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 109,468 155,853 292,536 360,471
Purchased Electricity for Resale 18,958 6,567 20,884 29,499
Purchased Electricity from AEP Affiliates 6,685 10,055 21,105 35,706
Other Operation 45,628 43,091 140,168 129,702
Maintenance 15,350 15,959 55,009 47,707
Depreciation and Amortization 33,676 30,381 96,940 89,284
Taxes Other Than Income Taxes 16,544 16,517 48,259 45,558
Income Taxes 23,443 23,970 38,013 39,418
--------- --------- --------- ---------
TOTAL 269,752 302,393 712,914 777,345
--------- --------- --------- ---------
OPERATING INCOME 60,618 59,229 122,344 120,861
Nonoperating Income 704 1,364 2,899 2,711
Nonoperating Expenses 669 577 2,735 1,453
Nonoperating Income Tax Expense (Credit) (398) 18 (1,295) (37)
Interest Charges 12,944 16,981 41,034 48,058
Minority Interest (898) (836) (2,592) (836)
--------- --------- --------- ---------
Income Before Cumulative Effect of Accounting Changes 47,209 42,181 80,177 73,262
Cumulative Effect of Accounting Changes (Net of Tax) - - - 8,517
--------- --------- --------- ---------
NET INCOME 47,209 42,181 80,177 81,779
Preferred Stock Dividend Requirements 57 57 172 172
--------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $47,152 $42,124 $80,005 $81,607
========= ========= ========= =========
The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- --------- ----------------- -----
DECEMBER 31, 2002 $135,660 $245,003 $334,789 $(53,683) $661,769
Common Stock Dividends (54,596) (54,596)
Preferred Stock Dividends (172) (172)
---------
TOTAL 607,001
---------
COMPREHENSIVE INCOME
- ----------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges 510 510
NET INCOME 81,779 81,779
---------
TOTAL COMPREHENSIVE INCOME 82,289
--------- --------- --------- ---------- ---------
SEPTEMBER 30, 2003 $135,660 $245,003 $361,800 $(53,173) $689,290
========= ========= ========= ========== =========
DECEMBER 31, 2003 $135,660 $245,003 $359,907 $(43,910) $696,660
Common Stock Dividends (45,000) (45,000)
Preferred Stock Dividends (172) (172)
---------
TOTAL 651,488
---------
COMPREHENSIVE INCOME
- ----------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (4,064) (4,064)
Minimum Pension Liability 23,066 23,066
NET INCOME 80,177 80,177
---------
TOTAL COMPREHENSIVE INCOME 99,179
--------- --------- --------- ---------- ---------
SEPTEMBER 30, 2004 $135,660 $245,003 $394,912 $(24,908) $750,667
========= ========= ========= ========== =========
See Notes to Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -----------------------------------------------------------
Production $1,660,575 $1,622,498
Transmission 631,169 615,158
Distribution 1,110,441 1,078,368
General 443,001 423,427
Construction Work in Progress 33,651 60,009
----------- -----------
TOTAL 3,878,837 3,799,460
Accumulated Depreciation and Amortization 1,700,023 1,617,846
----------- -----------
TOTAL - NET 2,178,814 2,181,614
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- -----------------------------------------------------------
Non-Utility Property, Net 4,050 3,808
Other Investments 4,675 4,710
----------- -----------
TOTAL 8,725 8,518
----------- -----------
CURRENT ASSETS
- -----------------------------------------------------------
Cash and Cash Equivalents 3,324 5,676
Other Cash Deposits 5,243 6,048
Advances to Affiliates 95,026 66,476
Accounts Receivable:
Customers 39,881 41,474
Affiliated Companies 19,112 10,394
Miscellaneous 7,849 4,682
Allowance for Uncollectible Accounts (2,573) (2,093)
Fuel Inventory 48,242 63,881
Materials and Supplies 34,928 33,775
Regulatory Asset for Under-recovered Fuel Costs 3,778 11,394
Risk Management Assets 27,056 19,715
Margin Deposits 2,063 5,123
Prepayments and Other 19,197 19,078
----------- -----------
TOTAL 303,126 285,623
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- -----------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 6,475 3,235
Unamortized Loss on Reacquired Debt 21,463 19,331
Minimum Pension Liability 35,487 -
Other 18,638 15,859
Long-term Risk Management Assets 15,234 12,178
Deferred Charges 61,081 55,605
----------- -----------
TOTAL 158,378 106,208
----------- -----------
TOTAL ASSETS $2,649,043 $2,581,963
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- --------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares $135,660 $135,660
Paid-in Capital 245,003 245,003
Retained Earnings 394,912 359,907
Accumulated Other Comprehensive Income (Loss) (24,908) (43,910)
----------- -----------
Total Common Shareholder's Equity 750,667 696,660
Cumulative Preferred Stock Not Subject to Mandatory Redemption 4,700 4,700
----------- -----------
Total Shareholders' Equity 755,367 701,360
Long-term Debt:
Nonaffiliated 547,160 741,594
Affiliated 50,000 -
----------- -----------
Total Long-term Debt 597,160 741,594
----------- -----------
TOTAL 1,352,527 1,442,954
----------- -----------
Minority Interest 1,043 1,367
----------- -----------
CURRENT LIABILITIES
- --------------------------------------------------------------
Long-term Debt Due Within One Year 209,974 142,714
Accounts Payable:
General 27,336 37,646
Affiliated Companies 25,061 35,138
Customer Deposits 32,133 24,260
Taxes Accrued 92,231 28,691
Interest Accrued 11,967 16,852
Risk Management Liabilities 28,922 11,361
Obligations Under Capital Leases 3,695 3,159
Regulatory Liability for Over-recovered Fuel 8,866 4,178
Other 36,060 53,753
----------- -----------
TOTAL 476,245 357,752
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- --------------------------------------------------------------
Deferred Income Taxes 355,368 349,064
Long-term Risk Management Liabilities 8,095 4,667
Reclamation Reserve 7,740 16,512
Regulatory Liabilities:
Asset Removal Costs 248,686 236,409
Deferred Investment Tax Credits 36,620 39,864
Excess Earnings 3,167 2,600
Other 17,868 18,779
Asset Retirement Obligations 27,043 8,429
Obligations Under Capital Leases 31,302 18,383
Deferred Credits and Other 83,339 85,183
----------- -----------
TOTAL 819,228 779,890
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $2,649,043 $2,581,963
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- -----------------------------------------------------
Net Income $80,177 $81,779
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (8,517)
Depreciation and Amortization 96,940 89,284
Deferred Income Taxes (7,303) 421
Deferred Investment Tax Credits (3,244) (3,245)
Deferred Property Taxes (9,687) (9,315)
Mark-to-Market of Risk Management Contracts 4,712 (11,497)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (9,812) (8,862)
Fuel, Materials and Supplies 14,486 10,095
Accounts Payable (20,387) (18,773)
Taxes Accrued 63,540 42,396
Fuel Recovery 12,304 (13,750)
Change in Other Assets (4,163) (1,901)
Change in Other Liabilities (2,620) 61,042
--------- ---------
Net Cash Flows From Operating Activities 214,943 209,157
--------- ---------
INVESTING ACTIVITIES
- -----------------------------------------------------
Construction Expenditures (68,238) (86,488)
Proceeds from Sale of Assets and Other 3,876 9,085
Change in Other Cash Deposits, Net 805 (3,723)
--------- ---------
Net Cash Flows Used For Investing Activities (63,557) (81,126)
--------- ---------
FINANCING ACTIVITIES
- -----------------------------------------------------
Issuance of Long-term Debt 92,441 143,041
Issuance of Long-term Debt - Affiliated 50,000 -
Retirement of Long-term Debt (222,457) (58,478)
Change in Advances to/from Affiliates, Net (28,550) (147,029)
Dividends Paid on Common Stock (45,000) (54,596)
Dividends Paid on Cumulative Preferred Stock (172) (172)
--------- ---------
Net Cash Flows Used For Financing Activities (153,738) (117,234)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (2,352) 10,797
Cash and Cash Equivalents at Beginning of Period 5,676 -
--------- ---------
Cash and Cash Equivalents at End of Period $3,324 $10,797
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $40,136,000 and $45,211,000 and for income taxes was $11,326,000 and
$26,166,000 in 2004 and 2003, respectively. Noncash acquisitions under capital leases were $14,226,000 in 2004. There were no
noncash capital lease acquisitions in 2003.
See Notes to Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to SWEPCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below are
the notes that apply to SWEPCo.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
--------------------------------------------------------
The notes to financial statements that follow are a combined presentation for
AEP's registrant subsidiaries. The following list indicates the registrants to
which the footnotes apply:
1. Significant Accounting Matters AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
2. New Accounting Pronouncements AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
3. Rate Matters APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
4. Customer Choice and APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC
Industry Restructuring
5. Commitments and Contingencies AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
6. Guarantees AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
7. Dispositions and Assets Held TCC
for Sale
8. Benefit Plans APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
9. Business Segments AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
10. Financing Activities AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
1. SIGNIFICANT ACCOUNTING MATTERS
------------------------------
General
- -------
The accompanying unaudited interim financial statements should be read in
conjunction with the 2003 Annual Report as incorporated in and filed
with our 2003 Form 10-K.
In the opinion of management, the unaudited interim financial statements
reflect all normal and recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for
interim periods.
Components of Accumulated Other Comprehensive Income (Loss)
- -----------------------------------------------------------
Accumulated Other Comprehensive Income (Loss) is included on the balance
sheet in the equity section. The components of Accumulated Other
Comprehensive Income (Loss) for AEP registrant subsidiaries is shown in
the following table.
September 30, December 31,
Components 2004 2003
----------- ---- ----
(in thousands)
Cash Flow Hedges:
-----------------
APCo $(15,935) $(1,569)
CSPCo (2,115) 202
I&M (8,543) 222
KPCo (585) 420
OPCo (3,483) (103)
PSO (2,323) 156
SWEPCo (3,880) 184
TCC (6,958) (1,828)
TNC (2,421) (601)
Minimum Pension Liability:
--------------------------
APCo $(50,519) $(50,519)
CSPCo (46,529) (46,529)
I&M (25,328) (25,328)
KPCo (6,633) (6,633)
OPCo (52,646) (48,704)
PSO (43,998) (43,998)
SWEPCo (21,028) (44,094)
TCC (63,515) (60,044)
TNC (26,117) (26,117)
During the first quarter of 2004, SWEPCo reclassified $23 million from
Accumulated Other Comprehensive Income (Loss) related to minimum pension
liability to Regulatory Assets ($35 million) and Deferred Income Taxes
($12 million) as a result of authoritative letters issued by the FERC
and the Arkansas and Louisiana commissions.
Accounting for Asset Retirement Obligations
- -------------------------------------------
We implemented SFAS 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003, which requires entities to record a liability
at fair value for any legal obligations for asset retirements in the
period incurred. Upon establishment of a legal liability, SFAS 143
requires a corresponding asset to be established which will be
depreciated over its useful life.
The following is a reconciliation of beginning and ending aggregate
carrying amounts of asset retirement obligations by registrant
subsidiary following the adoption of SFAS 143:
Balance At Balance at
January 1, Liabilities Liabilities September 30,
2004 Accretion Incurred Settled 2004
---------- --------- ----------- ----------- -------------
AEGCo (a) $1.1 $0.1 $- $- $1.2
APCo (a) 21.7 1.3 - (0.4) 22.6
CSPCo (a) 8.7 0.6 - - 9.3
I&M (b) 553.2 29.6 - - 582.8
OPCo (a) 42.7 2.5 - - 45.2
SWEPCo (c) 8.4 0.9 17.7 - 27.0
TCC (d) 218.8 12.4 - - 231.2
(a) Consists of asset retirement obligations related to ash ponds.
(b) Consists of asset retirement obligations related to ash ponds
($1.2 million at September 30, 2004) and nuclear
decommissioning costs for the Cook Plant ($581.6 million at
September 30, 2004).
(c) Consists of asset retirement obligations related to Sabine
Mining and Dolet Hills.
(d) Consists of asset retirement obligations related to nuclear
decommissioning costs for STP included in Liabilities Held
for Sale - Texas Generation Plants on TCC's Consolidated
Balance Sheets.
Accretion expense is included in Other Operation expense in the
respective income statements of the individual subsidiary registrants.
As of September 30, 2004 and December 31 2003, the fair value of assets
that are legally restricted for purposes of settling the nuclear
decommissioning liabilities totaled $902 million ($768 million for I&M
and $134 million for TCC) and $845 million ($720 million for I&M and
$125 million for TCC), respectively, recorded in Nuclear Decommissioning
and Spent Nuclear Fuel Disposal Trust Funds on I&M's Consolidated
Balance Sheets and in Assets Held for Sale - Texas Generation Plants on
TCC's Consolidated Balance Sheets.
Reclassification
- ----------------
Certain prior period financial statement items have been reclassified to
conform to current period presentation. Such reclassifications had no
impact on previously reported Net Income (Loss).
2. NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------
FIN 46 (revised December 2003)"Consolidation of Variable Interest
Entities" FIN 46R
- -----------------------------------------------------------------
We implemented FIN 46R, "Consolidation of Variable Interest Entities,"
effective March 31, 2004 with no material impact to our financial
statements. FIN 46R is a revision to FIN 46 which interprets the
application of Accounting Research Bulletin No. 51, "Consolidated
Financial Statements," to certain entities in which equity investors do
not have the characteristics of a controlling financial interest or do
not have sufficient equity at risk for the entity to finance its
activities without additional subordinated financial support from other
parties.
FASB Staff Position No. FAS 106-2, Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug Improvement
and Modernization Act of 2003
- ------------------------------------------------------------------------
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC implemented FASB
Staff Position (FSP) FAS 106-2, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization
Act of 2003," effective April 1, 2004, retroactive to January 1, 2004.
The new disclosure standard provides authoritative guidance on the
accounting for any effects of the Medicare prescription drug subsidy
under the Act. It replaces the earlier FSP FAS 106-1, under which APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC previously elected to
defer accounting for any effects of the Act until the FASB issued
authoritative guidance on the accounting for the Medicare subsidy.
Under FSP FAS 106-2, the current portion of the Medicare subsidy for
employers who qualify for the tax-free subsidy is a reduction of ongoing
FAS 106 cost, while the retroactive portion is an actuarial gain to be
amortized over the average remaining service period of active employees,
to the extent that the gain exceeds FAS 106's 10 percent corridor. The
Medicare subsidy reduced the FAS 106 accumulated postretirement benefit
obligation (APBO) related to benefits attributed to past service by $202
million. The tax-free subsidy reduced AEP's 2004 year-to-date net
periodic postretirement benefit cost, after adjustment to capitalization
of employee benefits costs as of a cost of construction, by a total of
$20 million.
The following table provides the reduction in the net periodic
postretirement benefit cost for the nine months ended September 30, 2004
for the AEP registrant subsidiaries:
Postretirement Benefit
Cost Reduction
----------------------
(in thousands)
APCo $3,146
CSPCo 1,575
I&M 2,267
KPCo 466
OPCo 2,697
PSO 1,041
SWEPCo 1,076
TCC 1,251
TNC 528
Future Accounting Changes
- -------------------------
The FASB's standard-setting process is ongoing and until new standards
have been finalized and issued by FASB, we cannot determine the impact
on the reporting of our operations that may result from any such future
changes. The FASB is currently working on several projects including
discontinued operations, business combinations, liabilities and equity,
revenue recognition, accounting for share-based compensation, pension
plans, asset retirement obligations, earnings per share calculations,
fair value measurements, accounting changes and related tax impacts. We
also expect to see more FASB projects as a result of their desire to
converge International Accounting Standards with those generally
accepted in the United States of America. The ultimate pronouncements
resulting from these and future projects could have an impact on our
future results of operations and financial position.
3. RATE MATTERS
------------
As discussed in our 2003 Annual Report, rate and regulatory proceedings
at the FERC and at several state commissions are ongoing. The Rate
Matters note within our 2003 Annual Report should be read in conjunction
with this report in order to gain a complete understanding of material
rate matters still pending, without significant changes since year-end.
The following sections discuss current activities.
TNC Fuel Reconciliation - Affecting TNC
- ----------------------------------------
In 2002, TNC filed with the PUCT to reconcile fuel costs, requesting to
defer any unrecovered portion applicable to retail sales within its
ERCOT service area for inclusion in the True-up Proceeding. This
reconciliation for the period from July 2000 through December 2001 will
be the final fuel reconciliation for TNC's ERCOT service territory.
In March 2003, the ALJ in this proceeding filed a Proposal for Decision
(PFD) with a recommendation that TNC's under-recovered retail fuel
balance be reduced. In March 2003, TNC established a provision for
probable disallowance of $13 million based on the recommendations in the
PFD. In May 2003, the PUCT reversed the ALJ on certain matters and
remanded TNC's final fuel reconciliation to the ALJ to consider two
issues: (1) the sharing of off-system sales margins from AEP's trading
activities with customers for five years per the PUCT's interpretation
of the Texas AEP/CSW merger settlement and (2) the inclusion of January
2002 fuel factor revenues and associated costs in the determination of
the under-recovery. The PUCT proposed that the sharing of off-system
sales margins for periods beyond the termination of the fuel factor
should be recognized in the final fuel reconciliation proceeding. This
would result in the sharing of margins for an additional three and
one-half years after the end of the Texas ERCOT fuel factor. While
management believes that the Texas merger settlement only provided for
sharing of margins during the period fuel and generation costs were
regulated by the PUCT, an additional provision of $10 million was
recorded in December 2003.
In December 2003, the ALJ issued a PFD in the remand phase of the TNC
fuel reconciliation recommending additional disallowances for the two
remand issues. TNC filed responses to the PFD, and the PUCT announced a
final ruling in the fuel reconciliation proceeding in January 2004
accepting the PFD. TNC received a written order in March 2004 and
increased its provision by $1.5 million. In March 2004, various parties,
including TNC, requested a rehearing of the PUCT's ruling. In May 2004,
the PUCT reversed its position on the inclusion of MTM amounts in the
allocation of system sales margins and remanded the case to the ALJ. As
a result, TNC recorded an additional provision of $12 million in the
second quarter of 2004 resulting in a provision for an over-recovery
balance of approximately $7 million.
On July 2, 2004, the parties to the MTM remand proceeding filed a
"Stipulation of Fact" in which all parties agreed to the quantification
of the remanded issue. With the amounts included in the "Stipulation of
Fact," the over-recovery balance would be $4 million. On October 13,
2004 the PUCT approved an order which included the amounts contained in
the "Stipulation of Fact." The PUCT issued an order in the fuel
reconciliation which reflected the "Stipulation of Fact" in October
2004. TNC will seek rehearing of the PUCT's order regarding issues other
than the issue covered by the stipulation. TNC may appeal to the Texas
District Court the PUCT's decision once all motions for rehearing have
been adjudicated. Management expects to adjust its provision to an
over-recovery balance of $4 million when it receives a final order in
the fourth quarter 2004. Although management believes it has adequately
provided for probable disallowances, a final order from the PUCT
disallowing amounts in excess of the established provision could have a
material adverse impact on TNC's future results of operations and cash
flows.
In February 2002, TNC received a final order from the PUCT in a previous
fuel reconciliation covering the period July 1997 through June 2000 and
reflected the order in its financial statements. This final order was
appealed to the Travis County District Court. In May 2003, the District
Court upheld the PUCT's final order. That order was appealed by certain
cities (the Cities) to the Third Court of Appeals. The Third Court of
Appeals issued a ruling on September 23, 2004 upholding the District
Court and the PUCT's final order. It is unknown at this time if the
Cities will appeal to the Texas Supreme Court or if the court will hear
the issue if they do.
TCC Fuel Reconciliation - Affecting TCC
- -----------------------------------------
In 2002, TCC filed its final fuel reconciliation with the PUCT to
reconcile fuel costs to be included in its deferred over-recovery
balance in the True-up Proceeding. This reconciliation covers the period
from July 1998 through December 2001.
Based on the PUCT ruling in the TNC proceeding related to similar
issues, TCC established a provision for probable adverse rulings of $81
million during 2003. On February 3, 2004, the ALJ issued a PFD in the
TCC case recommending that the PUCT disallow $140 million in eligible
fuel costs including some new items not considered in the TNC case, and
other items considered but not disallowed in the TNC ruling. Based on an
analysis of the ALJ's recommendations and the initial final order in the
TNC fuel reconciliation, TCC established an additional provision of $13
million during the first quarter of 2004. In May 2004, the PUCT accepted
most of the ALJ's recommendations in the TCC case, however, the PUCT
rejected the ALJ's recommendation to impute capacity to certain
energy-only purchased power contracts and remanded the issue to the ALJ
to determine if any energy-only purchased power contracts during the
reconciliation period include a capacity component that is not
recoverable in fuel revenues. In testimony filed in the remand
proceeding, TCC has asserted that its energy-only purchased power
contracts do not include any capacity component. Intervenors, including
the Office of Public Utility Counsel, have filed testimony recommending
that $15 million to $30 million of TCC's purchased power costs reflect
capacity costs which are not recoverable in the fuel reconciliations.
Hearings were held in October 2004 on this remand issue. As a result of
the PUCT's acceptance of most of the ALJ's recommendations in TCC's case
and the PUCT's remand decision in the TNC case regarding the inclusion
of MTM amounts in the allocation of AEP's net system sales margins, TCC
increased its provision by $47 million in the second quarter of 2004.
The over-recovery balance and the provisions for probable disallowances
totaled $210 million including interest at September 30, 2004.
At this time, management is unable to predict the outcome of this
proceeding. Management believes it has provided for all probable to-date
disallowances pending receipt of a final order. A final order has not
yet been issued in TCC's final fuel reconciliation. Management will continue
to challenge adverse decisions vigorously, including appeals if necessary.
An order from the PUCT, disallowing amounts in excess of the established
provision, couldhave a material adverse effect on TCC's future results of
operations and cash flows. Additional information regarding the True-up
Proceeding for TCC can be found in Note 4 "Customer Choice and Industry
Restructuring."
SWEPCo Texas Fuel Reconciliation - Affecting SWEPCo
- ---------------------------------------------------
In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in the
SPP. This reconciliation covers the period from January 2000 through
December 2002. During the reconciliation period, SWEPCo incurred $435
million of Texas retail eligible fuel expense. In November 2003,
intervenors and the PUCT Staff recommended fuel cost disallowances of
more than $30 million. In December 2003, SWEPCo agreed to a settlement
in principle with all parties in the fuel reconciliation. The settlement
provides for a disallowance in fuel costs of $8 million which was
recorded in December 2003. In April 2004, the PUCT approved the
settlement.
Virginia Fuel Factor Filing - Affecting APCo
- --------------------------------------------
On October 29, 2004 APCo filed with the Virginia SCC to increase its
fuel factor effective January 1, 2005. The requested factor is estimated
to increase revenues by approximately $19 million on an annual basis.
This increase reflects a continuing rise in the projected cost of coal
in 2005. This fuel factor adjustment will increase cash flows without
impacting results of operations as any over-recovery or under-recovery
of fuel costs would be deferred as a regulatory liability or a
regulatory asset.
TCC Rate Case - Affecting TCC
- -----------------------------
On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates
should not be reduced. Other municipalities served by TCC passed similar
rate review resolutions. In Texas, municipalities have original
jurisdiction over rates of electric utilities within their municipal
limits. Under Texas law, TCC must provide support for its rates to the
municipalities. TCC filed the requested support for its rates based on a
test year ending June 30, 2003 with all of its municipalities and the
PUCT on November 3, 2003. TCC's proposal would decrease its wholesale
transmission rates by $2 million or 2.5% and increase its retail energy
delivery rates by $69 million or 19.2%.
In February 2004, eight intervening parties and the PUCT Staff filed
testimony recommending reductions to TCC's requested $67 million rate
increase. The recommendations ranged from a decrease in existing rates
of approximately $100 million to an increase in TCC's current rates of
approximately $27 million. Hearings were held in March 2004. In May
2004, TCC agreed to a non-unanimous settlement on cost of capital
including capital structure and return on equity with all but two
parties in the proceeding. TCC agreed that the return on equity should
be established at 10.125% based upon a capital structure with 40% equity
resulting in a weighted cost of capital of 7.475%. The settlement and
other agreed adjustments reduced TCC's rate request from $67 million to
$41 million. The ALJs that heard the case issued their recommendations
on July 2, 2004, including a recommendation to approve the cost of
capital settlement. The ALJs recommended that an issue related to the
allocation of consolidated tax savings to the transmission and
distribution utility be remanded for additional evidence. On July 15,
2004, the PUCT remanded this issue to the ALJs. On August 19, 2004, in a
separate ruling the PUCT remanded six other issues to the ALJs
requesting revisions to clarify and further support the recommendations
in the PFD. In addition, the PUCT ordered TCC to calculate its revenue
requirements based upon the recommendations of the ALJs. On July 21,
2004, TCC filed its revenue requirements based upon the recommendations
of the ALJs. According to TCC's calculations, the ALJs' recommendations
reduce TCC's existing rates by somewhere between $33 million and $43 million
depending on the final resolution of the amount of consolidated tax
savings. Hearings were held on the consolidated tax savings remand issue
in September. The PUCT is expected to issue its decision by the end of
2004. Management is unable to predict the ultimate effect of this
proceeding on TCC's rates, revenues, results of operations, cash flows
and financial condition.
On September 2, 2004, a group of intervenors, with subsequent support of
the PUCT Staff, filed a request that a $30 million temporary, or
interim, rate reduction be ordered subject to refund or surcharge. On
September 24, 2004 the PUCT issued an order denying the motion for
reduced temporary rates.
Louisiana Compliance Filing - Affecting SWEPCo
- -----------------------------------------------
In October 2002, SWEPCo filed with the Louisiana Public Service
Commission (LPSC) detailed financial information typically utilized in a
revenue requirement filing, including a jurisdictional cost of service.
This filing was required by the LPSC as a result of its order approving
the merger between AEP and CSW. The LPSC's merger order also provides
that SWEPCo's base rates are capped at the present level through
mid-2005. In April 2004, SWEPCo filed updated financial information with
a test year ending December 31, 2003 as required by the LPSC. Both
filings indicated that SWEPCo's current rates should not be reduced.
Subsequently, direct testimony was filed on behalf of the LPSC
recommending a $15.4 million reduction in SWEPCo's Louisiana
jurisdictional base rates. SWEPCo's rebuttal testimony is due December
15, 2004. At this time, management is unable to predict the outcome of
this proceeding. If a rate reduction is ordered in the future, it would
adversely impact SWEPCo's results of operations and cash flows.
Louisiana Fuel Audit - Affecting SWEPCo
- ---------------------------------------
The LPSC is performing an audit of SWEPCo's historical fuel costs. In
addition, five SWEPCo customers filed a suit in the Caddo Parish
District Court in January 2003 and filed a complaint with the LPSC. The
customers claim that SWEPCo has overcharged them for fuel costs since
1975. The LPSC consolidated the customer complaint and audit. A status
conference is scheduled for December 16, 2004 to schedule a hearing
date. Although management believes that SWEPCo's fuel costs were proper
and fuel costs incurred prior to 1999 were approved by the LPSC, we are
unable to predict the outcome of these proceedings. If the actions of
the LPSC or the Court result in a material disallowance of SWEPCo's fuel
recoveries, it would have an adverse impact on results of operations and
cash flows. The LPSC Staff consultant made recommendations to reduce
recoverable fuel expense from SWEPCo's Louisiana retail customers. The
consultant recommended that SWEPCo be required to refund $3.9 million
(through December 2002) stating the amount should be recovered through
base rates versus the fuel factor. An additional amount of $1.4 million
for the period of January 2003 through September 2004 would also be
required to be refunded. In addition, the LPSC Staff contends that
SWEPCo's Pirkey Power Plant experienced poor performance during the
years 1999, 2001 and 2002 and that the incremental cost of replacement
power should be refunded. The consultant did not provide an amount
associated with this recommendation, but management believes that the
amount could be material. If the LPSC adopts any of the consultant's
recommendations, it would adversely impact SWEPCo's results of
operations and cash flows.
PSO Fuel and Purchased Power - Affecting PSO
- --------------------------------------------
In 2002, PSO experienced 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.
In July 2003, PSO filed with the Corporation Commission of the State of
Oklahoma (OCC) seeking to recover these reallocated costs over a period
of 18 months. In August 2003, the OCC Staff filed testimony recommending
PSO be granted recovery of $42.4 million of the reallocation over three
years. In September 2003, the OCC expanded the case to include a full
review of PSO's 2001 fuel and purchased power practices. PSO filed
testimony in February 2004. An intervenor and the OCC Staff filed
testimony in April 2004. The intervenor suggested that $8.8 million
related to the 2002 reallocation not be recovered from customers. The
Attorney General of Oklahoma also filed a statement of position,
indicating allocated off-system sales margins between and among AEP
operating companies were inconsistent with the FERC-approved Operating
Agreement and System Integration Agreement and if corrected could more
than offset the $44 million 2002 reallocation under-recovery. The
intervenor and the OCC Staff also believed off-system sales margins were
allocated incorrectly and that a reallocation by the intervenors of such
margins would reduce PSO's recoverable fuel by an additional $6.8
million for 2000 and $10.7 million for 2001, while under the OCC Staff
method, the reduction for 2001 would be $8.8 million. The intervenor and
the OCC Staff also recommend recalculation of fuel for years subsequent
to 2001 using the same revised methods. 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.
PSO Rate Review - Affecting PSO
- -------------------------------
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. Hearings are scheduled to
begin in February 2005 to address cost of service, fuel procurement and
resource planning issues.
On August 12, 2004, PSO filed a motion to amend the schedule to consider
new service quality and reliability requirements which took effect on
July 1, 2004. On August 30, 2004, the OCC approved a revised schedule.
On October 4, 2004, PSO filed supplemental information requesting
consideration of approximately $55 million of additional annual
operations and maintenance expenses and annual capital costs to enhance
system reliability. On November 4, 2004, PSO filed a plan with the OCC
seeking interim rate relief to fund a portion of the costs to meet
the new state service quality and reliability requirements pending
the outcome of the current case. In the filing, PSO seeks interim
approval to collect incremental distribution tree trimming costs of
approximately $29 million from its customers. The OCC Staff and
intervenors are scheduled to file testimony regarding their
recommendations on revenue requirement, fuel procurement, resource
planning and vegetation management in December 2004. Rebuttal
testimony is to be filed in January 2005 with hearings beginning in
February 2005. 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.
RTO Formation/Integration - Affecting APCo, CSPCo, I&M, KPCo, and OPCo
- ----------------------------------------------------------------------
Based on FERC approvals in response to non-affiliated companies'
requests to defer RTO formation costs, the AEP East companies deferred
costs incurred under FERC orders to originally form a new RTO (the
Alliance RTO) or subsequently to join an existing RTO (PJM). In July
2003, the FERC issued an order approving our continued deferral of both
Alliance RTO formation costs and PJM integration costs including the
deferral of a carrying charge thereon. The AEP East companies have
deferred approximately $35 million of RTO formation and integration
costs and related carrying charges through September 30, 2004. Amounts
per company are as follows.
Company (in millions)
------- -------------
APCo $9.8
CSPCo 4.1
I&M 7.6
KPCo 2.3
OPCo 10.9
As a result of the subsequent delay in the integration of AEP's East
transmission system into PJM, the FERC declined to rule, in its July
2003 order, on our request to transfer the deferrals to regulatory
assets, and to maintain such deferrals until such time as the costs can
be recovered from all users of AEP's East transmission system.
In its July 2003 order, the FERC indicated that it would review the
deferred costs at the time they are transferred to a regulatory asset
account and scheduled for amortization and recovery in the open access
transmission tariff (OATT) to be charged by PJM. Management believes
that the FERC will grant permission for prudently incurred deferred RTO
formation/integration costs to be amortized and included in the OATT.
Whether the amortized costs will be fully recoverable depends upon the
state regulatory commissions' treatment of the AEP East companies'
portion of the OATT as these companies file rate cases. Presently,
retail base rates are frozen or capped and cannot be increased for
retail customers of CSPCo and OPCo until 2006 and I&M until 2005.
In August 2004, we filed an application with the FERC dividing the RTO
formation/integration costs between PJM-billed integration costs including
related carrying charges, and all other RTO formation/integration costs. We
intend to file with the FERC to request that deferred PJM-billed integration
costs be recovered. The AEP East companies will be responsible for paying the
amount allocated by the FERC to the AEP zone since it will be attributable to
their internal load. In our August 2004 application, we requested permission
to amortize approximately one-half of the deferred costs within the AEP zone
over fifteen years beginning on January 1, 2005. We also requested to
begin amortizing the deferred PJM-billed integration costs on January 1, 2005,
but we did not propose an amortization period in the application.
In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO prior to July 1, 2004 and thereafter
only with the approval of the Virginia SCC, but required APCo join an
RTO by January 1, 2005. In January 2004, APCo filed with the Virginia
SCC a cost/benefit study covering the time period through 2014 as
required by the Virginia SCC. The study results show a net benefit of
approximately $98 million for APCo over the 11-year study period from
AEP's participation in PJM. In August 2004, the Virginia SCC approved a
stipulation that permits APCo to join PJM.
In July 2003, the KPSC denied KPCo's request to join PJM based in part
on a lack of evidence that it would benefit Kentucky retail customers.
In August 2003, KPCo sought and was granted a rehearing to submit
additional evidence. In December 2003, AEP filed with the KPSC a
cost/benefit study showing a net benefit of approximately $13 million
for KPCo over the five-year study period from AEP's participation in
PJM. In May 2004, the KPSC approved a stipulation that permits KPCo to
join PJM and the FERC approved the stipulation in June 2004.
In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to
certain conditions included in the order. The IURC's order stated that
AEP shall request and the IURC shall complete a review of Alliance
formation costs before any future recovery. I&M noted in its response to
the IURC that it deferred such costs under the July 2003 FERC order.
In November 2003, the FERC issued an order preliminarily finding that
AEP must fulfill its CSW merger condition to join an RTO by integrating
into PJM (transmission and markets) by October 1, 2004. The order was
based on PURPA 205(a), which allows the FERC to exempt electric
utilities from state law or regulation in certain circumstances. The
FERC set several issues for public hearing before an ALJ. Those issues
include whether the laws, rules, or regulations of Virginia and Kentucky
are preventing AEP from joining an RTO and whether the exceptions under
PURPA 205(a) apply. The FERC ALJ affirmed the FERC's preliminary
findings in March 2004. The FERC issued an order related to this matter
in June 2004 affirming its preliminary findings. In September 2004,
Virginia filed an offer of settlement with the FERC in which they agreed
to cease all attempts to obtain judicial relief from the June 2004 order
on the condition that the FERC vacate the order. The FERC has not ruled
on Virginia's settlement offer.
The AEP East companies integrated into PJM on October 1, 2004. The AEP
East state regulatory Commissions have approved our integration with PJM
and FERC has ordered us to defer our RTO formation/integration costs.
Such costs will be recovered on an amortization basis through an OATT
tariff charged to users of the system. The AEP East companies will also
be charged by PJM for use of the system. AEP plans to seek recovery for
the portion of the deferred RTO costs that are billed to the AEP East
companies by PJM in future rate proceedings. The AEP East companies will
expense their portion of the costs billed by PJM. Management is unable
to predict whether the FERC will grant a long enough amortization period
to allow for the opportunity for recovery of the non-PJM billed deferred
RTO formation/integration costs in the AEP East state retail
jurisdictions, and whether the state regulatory Commissions will
ultimately permit recovery of such costs billed to the AEP East
companies by PJM. If the FERC ultimately decides not to approve an
amortization period that would provide us with the opportunity to
include such costs in future retail rate filings or the FERC or the
state commissions deny recovery of our share of these costs, future
results of operations and cash flows could be adversely affected.
FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo, I&M,
KPCo and OPCo
- --------------------------------------------------------------------------
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 expanded PJM 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. The order provided that affected transmission
owners could file to offset the elimination of these revenues by
increasing rates or utilizing a transitional rate mechanism to recover
lost revenues that result from the elimination of the T&O rates. The
FERC also found that the T&O rates of certain other companies that were
then planning to join either PJM or Midwest Independent System Operator
(MISO) ("Former Alliance RTO Participants"), including AEP, may be
unjust, unreasonable, and unduly discriminatory or preferential for
energy delivered in the Combined Footprint. The FERC also initiated an
investigation and hearing in regard to these rates.
In November 2003, the FERC issued an order finding that the T&O rates of
the Former Alliance RTO Participants should also be eliminated for
transactions within the Combined Footprint. The order directed the RTOs
and Former Alliance RTO Participants, including AEP, to file compliance
rates to eliminate T&O rates prospectively within the Combined Footprint
and simultaneously implement a load-based transitional rate mechanism
called the seams elimination cost allocation (SECA), to mitigate the
lost T&O revenues for a two-year transition period beginning April 1,
2004. The FERC was expected to implement a new rate design after the
two-year period. As required by the FERC, AEP filed compliance tariff
changes in January 2004 to eliminate the T&O charges within the Combined
Footprint. Various parties raised issues with the SECA rate orders and
the FERC implemented settlement procedures before an ALJ.
In April 2004, the FERC approved a settlement that delayed elimination
of T&O rates until December 1, 2004 and provided principles and
procedures for development of a new rate design for the Combined
Footprint, to be effective on December 1, 2004. The settlement also
provides that if the process did not result in the implementation of a
new rate design on December 1, then the SECA rates will be implemented
and will remain in effect until a new rate is implemented by the FERC.
If implemented, the SECA rate would not be effective beyond March 31,
2006.
On September 16, 2004 the FERC Chief ALJ, acting as Settlement Judge,
reported to the FERC that attempts to settle the issues had failed, and
at least two competing long-term rate design proposals for the Combined
Footprint were filed on October 1, 2004. 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.
Indiana Fuel Order - Affecting I&M
- ----------------------------------
On August 27, 2003, the IURC ordered that certain parties must negotiate
the appropriate action on I&M's fuel cost recovery beginning March 1,
2004, following the February 2004 expiration of a fixed fuel adjustment
charge (fixed pursuant to a prior settlement of the Cook Nuclear Plant
outage issues). The fixed fuel adjustment charge capped fuel recoveries.
In an agreement in connection with AEP's planned corporate separation,
I&M agreed, contingent on AEP implementing the corporate separation, to
a fixed fuel adjustment charge beginning March 2004 and continuing
through December 2007. Although AEP has not corporately separated,
certain parties believe the fixed fuel adjustment charge should continue
beyond February 2004. Negotiations with the parties to resolve this
issue are ongoing. The IURC ordered that the fixed fuel adjustment
charge remain in place, on an interim basis, in March and April 2004.
In April 2004, the IURC issued an order that extended the interim fuel
factor for May through September 2004, subject to true-up to actual fuel
costs following the resolution of the issue regarding the corporate
separation agreement. The IURC also issued an order that reopened the
corporate separation docket to investigate issues related to the
corporate separation agreement. In July 2004, I&M filed for approval of
a fuel factor for the period October 2004 through March 2005. On
September 22, 2004, the IURC issued an order extending the interim fuel
factor for October 2004 through March 2005, subject to true-up upon
resolution of the corporation separation issues. At September 30, 2004,
I&M has over-recovered its fuel costs and has recorded a regulatory
liability to refund such over-recovery. However, if I&M's position
should shift to a net under-recovery, the fixed fuel adjustment factor,
capping the fuel revenues, could adversely affect its results of
operations and cash flows if recovery is denied by the IURC.
Michigan 2004 Fuel Recovery Plan - Affecting I&M
- ------------------------------------------------
A 1999 Michigan Public Service Commission (MPSC) order approved a
Settlement Agreement regarding the extended outage of the Cook Plant and
fixed I&M's Power Supply Cost Recovery (PSCR) factors for the St. Joseph
and Three Rivers rate areas through December 2003. As required, I&M
filed its 2004 PSCR Plan with the MPSC on September 30, 2003 seeking new
fuel and power supply recovery factors to be effective in 2004. A public
hearing was held on March 10, 2004. On June 4, 2004, the ALJ recommended
that SO2 and NOx net credits be excluded from the fuel recovery
mechanism. I&M filed its exceptions in June 2004. A MPSC order is
expected during the fourth quarter of 2004. As allowed by Michigan law,
the proposed factors were effective on January 1, 2004, subject to
review by the MPSC and possible adjustment. When SO2 and NOx are a net
cost exclusion from the fuel cost recovery mechanism, it will adversely
affect I&M's future results of operations and cash flows. On September
30, 2004, I&M filed its 2005 PSCR Plan.
4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
------------------------------------------
As discussed in the 2003 Annual Report, certain AEP subsidiaries are
affected by customer choice initiatives and industry restructuring. The
Customer Choice and Industry Restructuring note in the 2003 Annual
Report should be read in conjunction with this report in order to gain a
complete understanding of material customer choice and industry
restructuring matters without significant changes since year-end. The
following paragraphs discuss significant current events related to
customer choice and industry restructuring.
OHIO RESTRUCTURING - Affecting CSPCo and OPCo
- ---------------------------------------------
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. The MDP began on January 1,
2001 and is scheduled to terminate no later than December 31, 2005. The
Public Utilities Commission of Ohio (PUCO) may terminate the MDP for one
or more customer classes before that date if it determines either that
effective competition exists in the incumbent utility's certified
territory or that there is a twenty percent switching rate of the
incumbent utility's load by customer class. Following the MDP, retail
customers will receive cost-based regulated distribution and
transmission service from the incumbent utility whose distribution rates
will be approved by the PUCO and whose transmission rates will be
approved by the FERC. Retail customers will continue to have the right
to choose their electric power suppliers or receive Default Service,
which must be offered by the incumbent utility at market rates.
On December 17, 2003, the PUCO adopted a set of rules concerning the
method by which it will determine market rates for Default Service
following the MDP. The rules provide for a Market Based Standard Service
Offer (MBSSO) which would be a variable rate based on a transparent
forward market, daily market, and/or hourly market prices. The rules
also require a fixed-rate Competitive Bidding Process (CBP) for
residential and small nonresidential customers and permits a fixed-rate
CBP for large general service customers and other customer classes.
Customers who do not switch to a competitive generation provider can
choose between the MBSSO and the CBP. Customers who make no choice will
be served pursuant to the CBP. The rules also required that electric
distribution utilities file an application for MBSSO and CBP by July 1,
2004. CSPCo and OPCo were recently granted a waiver from making the
required MBSSO/CBP filing, pending the outcome of a rate stabilization
plan they filed with the PUCO in February 2004.
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 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.
For residential customers, however, if the temporary 5% generation rate
discount provided by the Ohio Act were eliminated prior to December 31,
2005 as permitted by the Ohio Act, the fixed increases would be adjusted
downward to reflect the effect of such elimination. Additionally, the
plan includes the opportunity to annually request an additional increase
averaging 4% per year for both companies in the event costs run beyond
the level currently anticipated. The plans would maintain distribution
rates through the end of 2008 for CSPCo and OPCo at the level effective
on December 31, 2005. Such rates could be adjusted for specified
reasons. Transmission charges could also be adjusted to reflect
applicable charges approved by the FERC related to open access
transmission, net congestion, and ancillary services. The plans also
provide for continued amortization and recovery of stranded transition
generation-related regulatory assets and for the deferral as regulatory
assets in 2004 and 2005 of RTO costs and carrying charges on
governmentally mandated, mainly environmental, capital expenditures.
Hearings were held in June 2004 on the Companies' proposed rate
stabilization plans. Briefs were submitted in July. The filings are
pending before the PUCO.
The PUCO, in a recent order involving a non-affiliated company's rate
stabilization plan, noted its reluctance to authorize automatic
increases in any portion of rates and required a PUCO determination in
the future prior to adjusting a rate component, instead of the automatic
increases to the rate component which had been proposed. It also held
that deferral during the MDP of certain expenses at issue in the case,
for recovery after the MDP, would violate the rate cap under the Ohio
Act. The PUCO has been asked in that case to reconsider these holdings
and that request currently is pending. OPCo's and CSPCo's rate plans and
the record in its cases are distinct from the rate plan and record
considered by the PUCO in its recent order. In that regard, 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 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.
As provided in stipulation agreements approved by the PUCO in 2000, we
are deferring customer choice implementation costs and related carrying
costs that are in excess of $40 million. The agreements provide for the
deferral of these costs as a regulatory asset until the next
distribution base rate cases. Through September 30, 2004, CSPCo incurred
$37 million and deferred $17 million and OPCo incurred $38 million and
deferred $18 million for probable future recovery in distribution rates.
Recovery of these regulatory assets will be subject to PUCO review in
future Ohio filings for new distribution rates. If the rate
stabilization plan is approved as filed, it would defer recovery of
these amounts until the next distribution rate filing. Management
believes that its deferred customer choice implementation costs were
prudently incurred and should be recoverable in future distribution
rates. If the PUCO determines that any of the deferred costs are
unrecoverable, it would have an adverse impact on future results of
operations and cash flows.
TEXAS RESTRUCTURING - Affecting SWEPCo, TCC and TNC
- ---------------------------------------------------
Texas Legislation enacted in 1999 provides the framework and timetable
to allow retail electricity competition for all Texas customers. On
January 1, 2002, customer choice of electricity supplier began in the
ERCOT area of Texas. Customer choice has been delayed in the SPP area of
Texas until at least January 1, 2007. TCC and TNC operate in ERCOT while
SWEPCo and a small portion of TNC's business is in SPP.
The Texas Legislation, among other things:
o provides for the recovery of stranded generation plant costs,
generation-related regulatory assets and other generation true-up
amounts 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 Texas Legislation also required vertically integrated utilities to
legally separate their generation and retail-related assets from their
transmission and distribution-related assets. Prior to 2002, TCC and TNC
functionally separated their operations. AEP formed new subsidiaries to
act as affiliated REPs for TCC and TNC effective January 1, 2002 (the
start date of retail competition). In December 2002, AEP sold its two
affiliated price-to-beat REPs to an unaffiliated company.
TEXAS TRUE-UP PROCEEDINGS
- -------------------------
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
(stranded generation costs),
o carrying charges on true-up amounts from January 1, 2002 (the
commencement date of retail competition), 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.
The PUCT adopted a rule in 2003 regarding the timing of the True-up
Proceedings scheduling TCC's filing in September 2004 or 60 days after
the completion of the sale of TCC's generation assets, if later. TNC
filed its true-up request in June 2004 and updated the filing in October
2004. Due to regulatory and contractual delays in the sale of its
generating assets, TCC has not filed its true-up request.
True-up Net Regulatory Asset (Liability) Recorded at September 30, 2004:
TCC TNC
--- ---
(in millions)
Components of Net Stranded Generation Costs:
Stranded Generation Plant Costs $1,079 $-
Unsecuritized Transition Generation Regulatory Asset 249 -
Unrefunded Excess Earnings (15) -
Other (56) -
------- -----
Net Stranded Generation Costs 1,257 -
------- -----
Components of Other Recoverable True-up Amounts:
Wholesale Capacity Auction True-up 480 -
Retail Clawback (a) (60) (14)
Deferred Over-recovered Fuel Balance (210) (7)
------- -----
Other Recoverable True-up Amounts 210 (21)
------- -----
Total Recorded Net True-up Regulatory Asset $1,467 $(21)
======= =====
(a) Only half of these amounts are actually recorded as regulatory
liabilities, as the other half are the responsibility of the
unaffiliated company that owns the affiliated price-to-beat REP.
See discussion below of the above amounts.
Net Stranded Generation Costs
- -----------------------------
The Texas Restructuring Legislation required utilities with stranded
generation plant costs to use market-based methods to value certain
generation assets for determining stranded generation plant costs. TCC
is the only AEP subsidiary that has stranded generation plant costs
under the Texas Legislation. TCC elected to use the sale of assets
method to determine the market value of TCC's generation assets for
determining stranded generation plant costs. For purposes of the True-up
Proceeding, the amount of stranded generation plant costs under this
market valuation methodology will be the amount by which the book value
of TCC's generation assets exceeds the market value of the generation
assets as measured by the net proceeds from the sale of the assets.
Based on the prices established by the generation asset sales, discussed
below, TCC recorded a net regulatory asset of $1.1 billion for its
stranded generation plant costs from the sale of TCC's generation assets
as shown in the table above, before accrual of any applicable carrying
charges discussed below.
In June 2003, TCC began actively seeking buyers for 4,497 megawatts of
their generation capacity in Texas. TCC received bids for all of their
generation plants. In January 2004, TCC agreed to sell its 7.81%
ownership interest in the Oklaunion Power Station to an unaffiliated
third party for approximately $43 million. In March 2004, TCC agreed to
sell its 25.2% ownership interest in STP for approximately $333 million
and its other coal, gas and hydro plants for approximately $430 million
to unaffiliated entities. Each sale is subject to specified price
adjustments. TCC sent right of first refusal notices to the co-owners of
Oklaunion and STP. TCC filed for FERC approval of the sales of
Oklaunion, STP and the fossil and hydro plants. TCC received a notice
from co-owners of Oklaunion and STP exercising their right of first
refusal; therefore, SEC approval will be required. The original
unaffiliated third party purchaser of Oklaunion has petitioned for a
court order declaring its contract valid and the co-owners' rights of
first refusal void. The sale of STP will also require approval from the
Nuclear Regulatory Commission. On July 1, 2004, TCC completed the sale
of the other coal, gas and hydro plants for approximately $425 million,
net of adjustments. The closings of the sales of STP and Oklaunion
plants are expected to occur in the first half of 2005, subject to
clarification of the rights of first refusal and the necessary
regulatory approvals. In addition, there could be delays in resolving
litigation with a third party affecting Oklaunion. In order to sell
these assets, TCC defeased all of its remaining outstanding first
mortgage bonds in May 2004. In December 2003, TCC recognized as a
regulatory asset an estimated impairment from the sale of their
generation assets. TCC is considering seeking a good cause exception to
the true-up rule to allow TCC to make its true-up filing prior to the
closings of the sales of all the generation assets.
In addition to its $1.1 billion of stranded generation plant costs, the
Texas legislation permits TCC to recover its remaining unsecuritized net
transition generation regulatory assets of $249 million less a
regulatory liability for the unrefunded excess earnings of $15 million,
discussed below. With other adjustments, TCC's recorded net stranded
generation costs total $1.3 billion.
Unrefunded Excess Earnings
- --------------------------
The Texas Legislation provides for the calculation of excess earnings
for each year from 1999 through 2001. The total excess earnings
determined by the PUCT for this three-year period were $3 million for
SWEPCo, $47 million for TCC and $19 million for TNC. TCC, TNC and SWEPCo
challenged the PUCT's treatment of fuel-related deferred income taxes
and appealed the PUCT's final 2000 excess earnings to the Travis County
District Court which upheld the PUCT ruling. After appealing the
District Court ruling upholding the PUCT decision, the Third Court of
Appeals reversed the PUCT order and the District Court's judgment. The
District Court remanded to the PUCT an appeal of the same issue from the
PUCT's 2001 order upon agreement of the parties after issuance of the
Third Court of Appeals decision. On September 14, 2004, the parties to
the PUCT remand reached an agreement which changed the method for calculating
excess earnings which, in turn, revised the calculation for 2000 and 2001
consistent with the ruling of the court. Revised excess earnings for the
three-year period were approximately $3 million for SWEPCo, $42 million for
TCC and $15 million for TNC. The PUCT issued a final order approving the
agreement in October 2004. Since an expense and regulatory liability had been
accrued in prior years in compliance with the PUCT orders, the companies
reversed a portion of their regulatory liability for the years 2000 and
2001 consistent with the Appeals Court's decision and credited
amortization expense during the third quarter of 2003. Under the Texas
legislation since TNC and SWEPCo do not have stranded generation plant
cost, excess earnings have been applied to reduce T&D capital
expenditures.
In 2001, the PUCT issued an order requiring TCC to return estimated
excess earnings by reducing distribution rates by approximately $55
million plus accrued interest over a five-year period beginning January
1, 2002. Since excess earnings amounts were expensed in 1999, 2000 and
2001, the order had no additional effect on reported net income but
reduces cash flows over the refund period. The remaining $15 million to
be refunded is recorded as a regulatory liability at September 30, 2004
and can be included as a reduction to TCC's stranded generation plant
costs. Management believes that TCC has stranded costs and that it was,
therefore, inconsistent with the Texas restructuring legislation for the
PUCT to order a refund prior to TCC's True-up Proceeding. TCC appealed
the PUCT's premature refund of excess earnings to the Travis County
District Court. That court affirmed the PUCT's decision and further
ordered that the refunds be provided to ultimate customers. TCC has
appealed the decision to the Third Court of Appeals.
Carrying Charges on Recoverable Stranded Costs
- ----------------------------------------------
In December 2001, the PUCT issued a rule concerning stranded cost
true-up proceedings stating, among other things, that carrying costs on
stranded costs would begin to accrue on the date that the PUCT issued
its final order in the True-up Proceeding. TCC and one other Texas
electric utility company filed a direct appeal of the rule to the Texas
Third Court of Appeals contending that carrying costs should commence on
January 1, 2002, the day that retail customer choice began in ERCOT.
The Third Court of Appeals ruled against the utilities, who then
appealed to the Texas Supreme Court. On June 18, 2004, the Texas Supreme
Court reversed the decision of the Third Court of Appeals determining
that a carrying cost should be accrued beginning January 1, 2002 and
remanded the proceeding to the PUCT for further consideration. The
Supreme Court determined that utilities with stranded costs are not
permitted to over-recover stranded costs and the PUCT should address
whether any portion of the 2002 and 2003 wholesale capacity auction
true-up regulatory asset includes a recovery of stranded costs or
carrying costs on stranded costs. A motion for rehearing with the
Supreme Court was denied and the ruling is final.
The PUCT in September 2004 considered the Supreme Court's decision in
true-up hearings held for another utility, CenterPoint Energy, Inc.
(CenterPoint). In that case while the PUCT has indicated preliminary
positions regarding the methodology to calculate recoverable carrying
costs, uncertainties exist as to the ultimate methodology that will be
adopted by the PUCT in its final order. The final order in the
CenterPoint case is expected to be issued later in November 2004. If the
final order in the CenterPoint case resolves the existing uncertainties,
TCC will record a carrying cost back to January 1, 2002 in the fourth
quarter of 2004 as an increase to its net true-up regulatory asset. At this time
management is unable to determine the amount of such carrying cost pending
receipt of the final CenterPoint order.
Wholesale Capacity Auction True-up
- ----------------------------------
The Texas Legislation required that electric utilities and their
affiliated power generation companies (PGC) offer for sale at auction,
in 2002, 2003 and thereafter, at least 15% of the PGC's Texas
jurisdictional installed generation capacity in order to promote
competitiveness in the wholesale market through increased availability
of generation. Actual market power prices received in the state-mandated
auctions are used to calculate the wholesale capacity auction true-up
revenues for the True-up Proceeding. According to PUCT rules, the
wholesale capacity auction true-up is only applicable to the years 2002
and 2003. TCC recorded a $480 million regulatory asset and related
revenues which represent the quantifiable amount of the wholesale
capacity auction true-up for the years 2002 and 2003.
In the true-up proceeding of CenterPoint, while the PUCT has indicated
preliminary positions regarding modifications of the calculation of the
wholesale capacity auction true-up reflecting CenterPoint's specific
facts and circumstances, uncertainties exist as to the ultimate
modifications and calculations that will be adopted by the PUCT in its
final order and if TCC's facts and circumstances will result in similar
results in its true-up proceeding. Specifically, the PUCT is evaluating
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. Upon issuance of a
final written order in the CenterPoint case, management will evaluate
the order and, if appropriate, record a provision for any amount that is
no longer probable of recovery as a result of final decisions in the
order which are applicable to TCC. The CenterPoint order is expected to
be issued later in November 2004.
Retail Clawback
- ---------------
The Texas Legislation provides for the affiliated price-to-beat (PTB)
retail electric providers (REPs) serving residential and small
commercial customers to refund to its T&D utility the excess of the PTB
revenues over market prices (subject to certain conditions and a
limitation of $150 per customer). This is the retail clawback. If, prior
to January 1, 2004, 40% of the load for the residential or small
commercial classes is served by competitive REPs, the retail clawback is
not applicable for that class of customer. During 2003, TCC and TNC
filed to notify the PUCT that competitive REPs serve over 40% of the
load in the small commercial class. The PUCT approved TCC's and TNC's
filings in December 2003. In 2002, AEP had accrued a regulatory
liability of approximately $9 million for the small commercial retail
clawback on its REP's books. When the PUCT certified that the REP's in
TCC and TNC service territories had reached the 40% threshold, the
regulatory liability was no longer required for the small commercial
class and was reversed in December 2003. Based upon customer information
filed by the unaffiliated company which operates as the price-to-beat
REP for TCC and TNC, we updated the estimated residential retail
clawback regulatory liability in May 2004. At September 30, 2004, TCC's
retail clawback regulatory liability was $30 million and TNC's was $7
million.
Fuel Balance Recoveries
- -----------------------
In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail
sales within its ERCOT service area for inclusion in the True-up
Proceeding. In January 2004, the PUCT announced a final ruling in TNC's
fuel reconciliation case. The PUCT issued a written order in March 2004.
Various parties, including TNC, requested rehearing of the PUCT's order.
In May 2004, the PUCT reversed certain prior rulings which resulted in
an over-recovered balance of $7 million. In October 2004, the PUCT
issued a final order which resulted in a reduction in the over-recovery
balance to $4 million. TNC filed an update to its true-up filing to
reflect the PUCT's final order in October 2004.
In 2002, TCC filed with the PUCT to reconcile fuel costs and to
establish its deferred over-recovery fuel balance for inclusion in the
True-up Proceeding. In May 2004, the PUCT remanded TCC's fuel proceeding
to the ALJ to consider additional evidence on one issue. TCC has
provided for a $210 million over-recovery balance at September 30, 2004.
Management believes that TCC has provided for all probable to-date
disallowances pending the remand and receipt of a final order. However,
due to the remand, management is unable to predict the amount of any
additional disallowances of TCC's final fuel over-recovery balance which
will be included in its True-up Proceeding until the remand is completed
and a final order issued.
See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 3 "Rate
Matters" for further discussion.
Stranded Cost Recovery
- ----------------------
When the True-up Proceeding is completed, TCC intends to file to recover
PUCT-approved net stranded generation costs and other true-up amounts,
plus appropriate carrying charges, through a non-bypassable competition
transition charge in the regulated T&D rates. TCC intends to seek to
securitize the approved net stranded generation costs plus related
carrying costs. The annual costs of securitization are recovered through
a non-bypassable transition charge collected by the T&D utility over the
term of the securitization bonds. The other approved net true-up items
will be recovered or refunded through a non-bypassable competition
transition wires charge or credit.
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. TCC expects that its True-up Proceeding filing will seek to
recover an amount in excess of the total of its recorded net regulatory
asset through September 30, 2004. This is primarily due to the fact that
TCC has not been able to accrue a carrying cost to date as a result of
uncertainties that exist. Management expects to be able to record a
carrying cost in the fourth quarter of 2004 based on the final order in
the CenterPoint case.
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, management cannot, at
this time, determine whether disallowances that may be applicable to
CenterPoint would be applicable to TCC. Management believes that TCC's recorded
regulatory assets are in compliance with Texas Legislation and TCC intends to
seek vigorously recovery of these amounts. If, however, management
determines that it is probable TCC cannot recover a portion of its
recorded net true-up regulatory asset of $1.5 billion and management is
able to estimate the amount of such non-recovery, TCC will record a
provision for such amount which could have a material adverse effect on
future results of operations, cash flows and possibly financial
condition. To the extent decisions in the TCC True-up Proceeding differ
from management expectations based in part on management's evaluation of
the final CenterPoint decision, additional material disallowances are
possible.
TNC 2004 True-up Filing
- -----------------------
In June 2004, TNC filed its True-up Proceeding including the fuel
reconciliation balance and the retail clawback calculation. The amount
of the deferred over recovered fuel balance recorded at September 30,
2004 was approximately $7 million. The retail clawback regulatory
liability included in the filing was adjusted in the second quarter of
2004 to $7 million (TNC's allocated portion of the REPs' retail
clawback) reflecting the number of customers served on January 1, 2004.
TNC filed an update to the true-up filing to reflect the final order in
its fuel reconciliation proceeding in October 2004 which adjusted its
over-recovery balance to $4.7 million inclusive of interest.
VIRGINIA RESTRUCTURING - Affecting APCo
- ---------------------------------------
In April 2004, the Governor of Virginia signed legislation which extends
the transition period for electricity restructuring, including capped
rates, through December 31, 2010. The legislation provides specified
cost recovery opportunities during the capped rate period, including two
optional general base rate changes and an opportunity for timely
recovery, through a separate rate mechanism, of certain incremental
environmental and reliability costs incurred on and after July 1, 2004.
5. COMMITMENTS AND CONTINGENCIES
-----------------------------
As discussed in the Commitments and Contingencies note within the 2003
Annual Report, certain AEP subsidiaries continue to be involved in
various legal matters. The 2003 Annual Report should be read in
conjunction with this report in order to understand the other material
nuclear and operational matters without significant changes since their
disclosure in the 2003 Annual Report. The material matters discussed in
the 2003 Annual Report without significant changes in status since
year-end include, but are not limited to, (1) nuclear matters, (2)
construction commitments, (3) potential uninsured losses, and (4) FERC
proposed Standard Market Design. See disclosure below for significant
matters with changes in status subsequent to the disclosure made in the
2003 Annual Report.
ENVIRONMENTAL
- -------------
Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo,
I&M, and OPCo
- ----------------------------------------------------------------------
The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo
and other unaffiliated utilities modified certain units at coal-fired
generating plants in violation of the new source review requirements of
the Clean Air Act (CAA). The Federal EPA filed its complaints against
AEP subsidiaries in U.S. District Court for the Southern District of
Ohio. The court also consolidated a separate lawsuit, initiated by
certain special interest groups, with the Federal EPA case. The alleged
modifications relate to costs that were incurred at the generating units
over a 20-year period.
Under the CAA, if a plant undertakes a major modification that directly
results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution
control technology. This requirement does not apply to activities such
as routine maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and efficient
operation of the plant. The CAA authorizes civil penalties of up to
$27,500 per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). In 2001, the District Court ruled claims for
civil penalties based on activities that occurred more than five years
before the filing date of the complaints cannot be imposed. There is no
time limit on claims for injunctive relief.
On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in
order to "perfect" its complaint in the pending litigation. The NOV
expands the number of alleged "modifications" undertaken at the
Muskingum River, Cardinal, Conesville and Tanners Creek plants during
scheduled outages on these units from 1979 through the present.
Approximately one-third of the allegations in the NOV are already
contained in allegations made by the states or the special interest
groups in the pending litigation. The Federal EPA filed a motion to
amend its complaint and to expand the scope of the pending litigation.
The AEP subsidiaries opposed that motion. In September 2004, the judge
disallowed the addition of claims to the pending case. The judge also
granted motions to dismiss a number of allegations in the original
filing.
On August 7, 2003, the District Court issued a decision following a
liability trial in a case pending in the Southern District of Ohio
against Ohio Edison Company, an unaffiliated utility. The District Court
held that replacements of major boiler and turbine components that are
infrequently performed at a single unit, that are performed with the
assistance of outside contractors, that are accounted for as capital
expenditures, and that require the unit to be taken out of service for a
number of months are not "routine" maintenance, repair, and replacement.
The District Court also held that a comparison of past actual emissions
to projected future emissions must be performed prior to any non-routine
physical change in order to evaluate whether an emissions increase will
occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all
of the challenged activities in that case were not routine, and that the
changes resulted in significant net increases in emissions for certain
pollutants. A remedy trial was scheduled for July 2004, but has been
postponed until January 2005 to facilitate further settlement
negotiations.
Management believes that the Ohio Edison decision fails to properly
evaluate and apply the applicable legal standards. The facts in the AEP
case also vary widely from plant to plant. Further, the Ohio Edison
decision is limited to liability issues, and provides no insight as to
the remedies that might ultimately be ordered by the Court.
On August 26, 2003, the District Court for the Middle District of South
Carolina issued a decision on cross-motions for summary judgment prior
to a liability trial in a case pending against Duke Energy Corporation,
an unaffiliated utility. The District Court denied all the pending
motions, but set forth the legal standards that will be applied at the
trial in that case. The District Court determined that the Federal EPA
bears the burden of proof on the issue of whether a practice is "routine
maintenance, repair, or replacement" and on whether or not a
"significant net emissions increase" results from a physical change or
change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the
relevant source category" in determining if it is "routine." Further,
the Federal EPA must calculate emissions by determining first whether a
change in the maximum achievable hourly emission rate occurred as a
result of the change, and then must calculate any change in annual
emissions holding hours of operation constant before and after the
change. The Federal EPA requested reconsideration of this decision, or
in the alternative, certification of an interlocutory appeal to the
Fourth Circuit Court of Appeals, and the District Court denied the
Federal EPA's motion. On April 13, 2004, the parties filed a joint
motion for entry of final judgment, based on stipulations of relevant
facts that obviated the need for a trial, but preserving plaintiffs'
right to seek an appeal of the federal prevention of significant
deterioration (PSD) claims. On April 14, 2004, the Court entered final
judgment for Duke Energy on all of the PSD claims made in the amended
complaints, and dismissed all remaining claims with prejudice. The
United States subsequently filed a notice of appeal to the Fourth
Circuit Court of Appeals. The case was briefed in September 2004.
On June 24, 2003, the United States Court of Appeals for the 11th
Circuit issued an order invalidating the administrative compliance order
issued by the Federal EPA to the Tennessee Valley Authority for alleged
CAA violations. The 11th Circuit determined that the administrative
compliance order was not a final agency action, and that the enforcement
provisions authorizing the issuance and enforcement of such orders under
the CAA are unconstitutional. The United States filed a petition for
certiorari with the United States Supreme Court and on May 3, 2004, that
petition was denied.
On June 26, 2003, the United States Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group
(UARG), of which the AEP subsidiaries are members, to reopen petitions
for review of the 1980 and 1992 Clean Air Act rulemakings that are the
basis for the Federal EPA claims in the AEP case and other related
cases. On August 4, 2003, UARG filed a motion to separate and expedite
review of their challenges to the 1980 and 1992 rulemakings from other
unrelated claims in the consolidated appeal. The Circuit Court denied
that motion on September 30, 2003. The central issue in these petitions
concerns the lawfulness of the emissions increase test, as currently
interpreted and applied by the Federal EPA in its utility enforcement
actions. A decision by the D. C. Circuit Court could significantly
impact further proceedings in the AEP case. Briefing continues in this
case and oral argument is scheduled for January 2005.
On August 27, 2003, the Administrator of the Federal EPA signed a final
rule that defines "routine maintenance repair and replacement" to
include "functionally equivalent equipment replacement." Under the new
final rule, replacement of a component within an integrated industrial
operation (defined as a "process unit") with a new component that is
identical or functionally equivalent will be deemed to be a "routine
replacement" if the replacement does not change any of the fundamental
design parameters of the process unit, does not result in emissions in
excess of any authorized limit, and does not cost more than twenty
percent of the replacement cost of the process unit. The new rule is
intended to have a prospective effect, and was to become effective in
certain states 60 days after October 27, 2003, the date of its
publication in the Federal Register, and in other states upon completion
of state processes to incorporate the new rule into state law. On
October 27, 2003 twelve states, the District of Columbia and several
cities filed an action in the United States Court of Appeals for the
District of Columbia Circuit seeking judicial review of the new rule.
The UARG has intervened in this case. On December 24, 2003, the Circuit
Court granted a motion from the petitioners to stay the effective date
of this rule, which had been December 26, 2003.
Management is unable to estimate the loss or range of loss related to
any contingent liability the AEP subsidiaries might have for civil
penalties under the CAA proceedings. Management is also unable to
predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be
determined by the Court. If the AEP System companies do not prevail, any
capital and operating costs of additional pollution control equipment
that may be required, as well as any penalties imposed, would adversely
affect future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated rates and
market prices for electricity.
In December 2000, Cinergy Corp., an unaffiliated utility, which operates
certain plants jointly owned by CSPCo, reached a tentative agreement
with the Federal EPA and other parties to settle litigation regarding
generating plant emissions under the Clean Air Act. Negotiations are
continuing between the parties in an attempt to reach final settlement
terms. Cinergy's settlement could impact the operation of Zimmer Plant
and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%,
respectively, by CSPCo). Until a final settlement is reached, CSPCo will
be unable to determine the settlement's impact on its jointly owned
facilities and its future results of operations and cash flows.
On July 21, 2004, the Sierra Club issued a notice of intent to file a
citizen suit claim against DPL, Inc., Cinergy Corporation, CSPCo, and
The Dayton Power & Light Company for alleged violations of the New
Source Review programs at the Stuart Station. CSPCo owns a 26% share of
the Stuart Station. On September 21, 2004, the Sierra Club filed a
complaint under the citizen suit provisions of the CAA in the United
States District Court for the Southern District of Ohio alleging that
violations of the PSD and New Source Performance Standards requirements
of the CAA and the opacity provisions of the Ohio state implementation
plan occurred at the J.M. Stuart Station, and seeking injunctive relief
and civil penalties. Management believes the allegations in the
complaint are without merit, and intends to defend vigorously this
action. Management is unable to predict the timing of any future action
by the special interest group or the effect of such actions on future
operations or cash flows.
SWEPCo Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo
- --------------------------------------------------------------------------
On July 13, 2004, two special interest groups issued a notice of intent
to commence a citizen suit under the Clean Air Act for alleged
violations of various permit conditions in permits issued to SWEPCo's
Welsh, Knox Lee, and Pirkey plants. This notice was prompted by
allegations made by a terminated AEP employee. The allegations at the
Welsh Plant concern compliance with emission limitations on particulate
matter and carbon monoxide, compliance with a referenced design heat
input value, and compliance with certain reporting requirements. The
allegations at the Knox Lee Plant relate to the receipt of an
off-specification fuel oil, and the allegations at Pirkey Plant relate
to testing and reporting of volatile organic compound emissions. No
action can be commenced until 60 days after the date of notice.
On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ)
issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant
containing a summary of findings resulting from a compliance
investigation at the plant. The summary includes allegations concerning
compliance with certain recordkeeping and reporting requirements,
compliance with a referenced design heat input value in the Welsh
permit, compliance with a fuel sulfur content limit, and compliance with
emission limits for sulfur dioxide.
On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo
relating to the off-specification fuel oil deliveries at the Knox Lee
Plant. On August 30, 2004, TCEQ issued a Notice of Enforcement to SWEPCo
relating to the reporting of volatile organic compound emissions at the
Pirkey Plant.
SWEPCo has previously reported to the TCEQ, deviations related to the
receipt of off-specification fuel at Knox Lee, the volatile organic
compound emissions at Pirkey, and the referenced recordkeeping and
reporting requirements and heat input value at Welsh. SWEPCo is
preparing additional responses to the Notice of Enforcement and the
notice from the special interest groups. Management is unable to predict
the timing of any future action by TCEQ or the special interest groups
or the effect of such actions on results of operations, financial
condition or cash flows.
Carbon Dioxide Public Nuisance Claims - Affecting AEP System
- -------------------------------------------------------------
On July 21, 2004, attorneys general from eight states and the
corporation counsel for the City of New York filed an action in federal
district court for the Southern District of New York against AEP, AEPSC
and four other unaffiliated governmental and investor-owned electric
utility systems. That same day, a similar complaint was filed in the
same court against the same defendants by the Natural Resources Defense
Council on behalf of two special interest groups. The actions allege
that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts
associated with global warming, and seek injunctive relief in the form
of specific emission reduction commitments from the defendants. In
September 2004, the defendants, including AEP and AEPSC, filed a motion
to dismiss the lawsuits. Management believes the actions are without
merit and intends to defend vigorously against the claims.
Nuclear Decommissioning - Affecting TCC
- ---------------------------------------
As discussed in the 2003 Annual Report, decommissioning costs are
accrued over the service life of STP. The licenses to operate the two
nuclear units at STP expire in 2027 and 2028. TCC had estimated its
portion of the costs of decommissioning STP to be $289 million in 1999
nondiscounted dollars. TCC is accruing and recovering these
decommissioning costs through rates based on the service life of STP at
a rate of approximately $8 million per year.
In May 2004, an updated decommissioning study was completed for STP. The
study estimates TCC's share of the decommissioning costs of STP to be
$344 million in nondiscounted 2004 dollars. TCC is currently analyzing
the STP study to determine the effect on our asset retirement
obligations (ARO) and will make any appropriate adjustments to the ARO
liability and related regulatory asset in the fourth quarter 2004. As
discussed in Note 7, TCC is in the process of selling its ownership
interest in STP to a non-affiliate, and upon completion of the sale it
is anticipated that TCC will no longer be obligated for nuclear
decommissioning liabilities associated with STP.
OPERATIONAL
- -----------
Power Generation Facility - Affecting OPCo
- ------------------------------------------
AEP has 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 AEP. AEP has 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.
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 OPCo separately filed declaratory judgment
actions in the United States District Court for the Southern District of
New York. OPCo alleges that TEM has breached the PPA, and is seeking a
determination of OPCo's 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 OPCo's breaches. If the PPA is deemed
terminated or found to be unenforceable by the court, OPCo could be
adversely affected to the extent it is unable to find other purchasers
of the power with similar contractual terms and to the extent OPCo does
not fully recover claimed termination value damages from TEM. However,
OPCo has entered an agreement with an affiliate that eliminates OPCo's
market exposure related to the PPA. 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
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.
Merger Litigation - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo, TCC and TNC
- -----------------------------------------------------------------------
In 2002, the U.S. Court of Appeals for the District of Columbia ruled
that the SEC failed to prove that the June 15, 2000 merger of AEP with
CSW meets the requirements of the PUHCA and sent the case back to the
SEC for further review. Specifically, the court told the SEC to revisit
the basis for its conclusion that the merger met PUHCA requirements that
utilities be "physically interconnected" and confined to a "single area or
region." In August 2004, the SEC announced it would conduct hearings on this
issue. The hearing is scheduled for January 2005.
In its June 2000 approval of the merger, the SEC agreed with AEP that
the companies' systems are integrated because they have transmission
access rights to a single high-voltage line through Missouri and also
met the PUHCA's single region requirement. In its ruling, the appeals
court said that the SEC failed to support and explain its conclusions
that the interconnection and single region requirements are satisfied.
Management believes that the merger meets the requirements of the PUHCA
and expects the matter to be resolved favorably.
Enron Bankruptcy - Affecting APCo, CSPCo, I&M, KPCo and OPCo
- ----------------------------------------------------------------------
In 2002, certain subsidiaries of AEP 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 subsidiaries of AEP had open trading
contracts and trading accounts receivables and payables with Enron. In
addition, on June 1, 2001, AEP purchased Houston Pipe Line Company (HPL)
from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.
Enron Bankruptcy - Commodity trading settlement disputes - In September
2003, Enron filed a complaint in the Bankruptcy Court against AEPES
challenging AEP's offsetting of receivables and payables and related
collateral across various Enron entities and seeking payment of
approximately $125 million plus interest in connection with gas-related
trading transactions. The AEP subsidiaries have asserted their right to
offset trading payables owed to various Enron entities against trading
receivables due to several AEP subsidiaries. The parties are currently
in non-binding court-sponsored mediation.
In December 2003, Enron filed a complaint in the Bankruptcy Court
against AEPSC seeking approximately $93 million plus interest in
connection with a transaction for the sale and purchase of physical
power among Enron, AEP and Allegheny Energy Supply, LLC during November
2001. Enron's claim seeks to unwind the effects of the transaction. AEP
believes it has several defenses to the claims in the action being
brought by Enron. The parties are currently in non-binding
court-sponsored mediation.
Enron Bankruptcy - Summary - The amount expensed in prior years in
connection with the Enron bankruptcy was based on an analysis of
contracts where AEP and Enron entities are counterparties, the
offsetting of receivables and payables, the application of deposits from
Enron entities and management's analysis of the HPL related purchase
contingencies and indemnifications. As noted above, Enron has challenged
the offsetting of receivables and payables. Although management is
unable to predict the outcome of these lawsuits it is possible that
their resolution could have an adverse impact on our results of
operations, cash flows or financial condition.
Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC
- ------------------------------------------------------------
Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider
(REP), filed a lawsuit in federal District Court in Corpus Christi,
Texas, in July 2003, against AEP and four of its subsidiaries, including
TCC and TNC, certain unaffiliated energy companies and ERCOT. The action
alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made
against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price
spikes requiring TCE to post additional collateral and ultimately forced
it into bankruptcy when it was unable to raise prices to its customers
due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary
damages and court costs. Two additional parties, Utility Choice, LLC and
Cirro Energy Corporation, have sought leave to intervene as plaintiffs
asserting similar claims. AEP and its subsidiaries filed a Motion to
Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. AEP and its subsidiaries filed a Motion to Dismiss the
amended complaint. In June 2004, the Court dismissed all claims against
the AEP companies. TCE has appealed the trial court's decision to the
United States Court of Appeals for the Fifth Circuit.
Energy Market Investigation - Affecting AEP System
- --------------------------------------------------
AEP and other energy market participants received data requests,
subpoenas and requests for information from the FERC, the SEC, the PUCT,
the U.S. Commodity Futures Trading Commission (CFTC), the U.S.
Department of Justice and the California attorney general during 2002.
Management responded to the inquiries and provided the requested
information and has continued to respond to supplemental data requests
in 2003 and 2004.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES
in federal district court in Columbus, Ohio. The CFTC alleges that AEP
and AEPES provided false or misleading information about market
conditions and prices of natural gas in an attempt to manipulate the
price of natural gas in violation of the Commodity Exchange Act. The
CFTC seeks civil penalties, restitution and disgorgement of benefits.
AEP responded to the complaint in September 2004. In 2003, AEP recorded a
provision related to these matters. AEP has engaged in settlement discussions
with several agencies and is evaluating whether to conclude settlements in order
to put these investigations behind us even though management believes it has
meritorious legal positions and defenses. If management elects to settle all
matters, the payment could exceed the 2003 provision and could have a material
impact on our 2004 earnings and cash flows.
FERC Market Power Mitigation - Affecting AEP System
- ---------------------------------------------------
In April 2004, the FERC issued two orders concerning utilities' ability
to sell wholesale electricity at market-based rates. In the first order,
the FERC adopted two new interim screens for assessing potential
generation market power of applicants for wholesale market based rates,
and described additional analyses and mitigation measures that could be
presented if an applicant does not pass one of these interim screens.
These two screening tests include a "pivotal supplier" test which
determines if the market load can be fully served by alternative
suppliers and a "market share" test which compares the amount of surplus
generation at the time of the applicant's minimum load. In July 2004,
the FERC issued an order on rehearing affirming its conclusions in the
April order and directing AEP and two unaffiliated utilities to file
generation market power analyses within 30 days. In the second order,
the FERC initiated a rulemaking to consider whether the FERC's current
methodology for determining whether a public utility should be allowed
to sell wholesale electricity at market-based rates should be modified
in any way.
On August 9, 2004, AEP submitted its Market Power Analysis pursuant to
the FERC's Orders on Rehearing. The analysis focused on the three major
areas in which AEP serves load and owns generation resources -- ECAR,
SPP and ERCOT, and the "first tier" control areas for each of those
areas.
The pivotal supplier and market share screen analyses that AEP filed
demonstrated that AEP does not possess market power in any of the
control areas to which it is directly connected (first-tier markets).
AEP passed both screening tests in all of its "first tier" markets. In
its three "home" control areas, AEP easily passed the pivotal supplier
test. AEP, as part of PJM, also passes the market share screen for the
PJM destination market. AEP also passed the market share screen for
ERCOT. AEP did not pass the market share screen as designed by the FERC
for the SPP control area. Consequently, AEP also submitted substantial
additional information, including historical purchase and sales data
that demonstrates that AEP does not possess market power in any of the
"home" destination markets. AEP requested that its existing market-based
pricing authorization in all markets be continued based on this
analysis. AEP also requested that the FERC rule without instituting a
proceeding and without setting a refund date. This case is pending.
6. GUARANTEES
----------
There are no material liabilities recorded for guarantees in accordance
with FIN 45. There is no collateral held in relation to any guarantees
and there is no recourse to third parties in the event any guarantees
are drawn unless specified below.
Letter of Credit
- ----------------
TCC has entered into a standby letter of credit (LOC) with third
parties. This LOC covers credit enhancements for issued bonds. This LOC
was issued in TCC's ordinary course of business. At September 30, 2004,
the maximum future payments of the LOC are $43 million which matures
November 2005. There is no recourse to third parties in the event this
letter of credit is drawn.
SWEPCo
- ------
In connection with reducing the cost of the lignite mining contract for
its Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain
conditions, to assume the capital lease obligations and term loan
payments of the mining contractor, Sabine Mining Company (Sabine). In
the event Sabine defaults under any of these agreements, SWEPCo's total
future maximum payment exposure is approximately $54 million with
maturity dates ranging from June 2005 to February 2012.
As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining, SWEPCo has agreed to provide
guarantees of mine reclamation in the amount of approximately $85
million. Since SWEPCo uses self-bonding, the guarantee provides for
SWEPCo to commit to use its resources to complete the reclamation in the
event the work is not completed by a third party miner. At September 30,
2004, the cost to reclaim the mine in 2035 is estimated to be
approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.
On July 1, 2003, SWEPCo consolidated Sabine due to the application of
FIN 46. Upon consolidation, SWEPCo recorded the assets and liabilities
of Sabine ($78 million). Also, after consolidation, SWEPCo currently
records all expenses (depreciation, interest and other operation
expense) of Sabine and eliminates Sabine's revenues against SWEPCo's
fuel expenses. There is no cumulative effect of an accounting change
recorded as a result of the requirement to consolidate, and there is no
change in net income due to the consolidation of Sabine. SWEPCo does not
have an ownership interest in Sabine.
Indemnifications and Other Guarantees
- -------------------------------------
All of the registrant subsidiaries enter into certain types of
contracts, which would require indemnifications. Typically these
contracts include, but are not limited to, sale agreements, lease
agreements, purchase agreements and financing agreements. Generally
these agreements may include, but are not limited to, indemnifications
around certain tax, contractual and environmental matters. With respect
to sale agreements, exposure generally does not exceed the sale price.
Registrant subsidiaries cannot estimate the maximum potential exposure
for any of these indemnifications entered into prior to December 31,
2002 due to the uncertainty of future events. In 2003 and during the
first nine months of 2004, registrant subsidiaries entered into sale
agreements which included indemnifications with a maximum exposure that
was not significant for any individual registrant subsidiary except for
TCC which entered into an indemnification of $129 million relating to
the sale of its generation assets in July 2004 (see Note 7). There are
no material liabilities recorded for any indemnifications.
Registrant subsidiaries are jointly and severally liable for activity
conducted by AEPSC on the behalf of AEP East and West companies and for
activity conducted by any AEP registrant subsidiary pursuant to the
system integration agreement.
Certain registrant subsidiaries lease certain equipment under a master
operating lease. Under the lease agreement, the lessor is guaranteed to
receive up to 87% of the unamortized balance of the equipment at the end
of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, we have
committed to pay the difference between the fair market value and the
unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At September 30, 2004, the maximum potential loss
by subsidiary for these lease agreements assuming the fair market value
of the equipment is zero at the end of the lease term is as follows:
Maximum Potential Loss
Subsidiary (in millions)
---------- -------------
APCo $ 5
CSPCo 2
I&M 3
KPCo 1
OPCo 4
PSO 4
SWEPCo 4
TCC 6
TNC 3
7. DISPOSITIONS AND ASSETS HELD FOR SALE
-------------------------------------
DISPOSITIONS COMPLETED DURING THIRD QUARTER 2004
- ------------------------------------------------
Texas Plants - TCC Generation Assets
- ------------------------------------
In December 2002, TCC filed a plan of divestiture with the PUCT
proposing to sell all of its power generation assets, including the
eight gas-fired generating plants that were either deactivated or
designated as "reliability must run" status.
During the fourth quarter of 2003, after receiving indicative bids from
interested buyers, TCC recorded a $938 million impairment loss and
changed the classification of the plant assets from plant in service to
Assets Held for Sale - Texas Generation Plants. In accordance with Texas
legislation, the $938 million impairment was offset by the establishment
of a regulatory asset, which is expected to be recovered through a wires
charge, subject to the final outcome of the True-up Proceeding. As a
result of the True-up Proceeding, if TCC is unable to recover all or a
portion of its requested costs (see Note 4), any unrecovered costs could
have a material adverse effect on TCC's results of operations, cash
flows and possibly financial condition.
In March 2004, TCC signed an agreement to sell eight natural gas plants,
one coal-fired plant and one hydro plant to a non-related joint venture.
The sale was completed in July 2004 for approximately $425 million, net
of adjustments. The sale did not have a significant effect on TCC's
results of operations during the periods ending September 30, 2004.
DISPOSITIONS ANTICIPATED BEING COMPLETED DURING FIRST HALF 2005
- ---------------------------------------------------------------
Texas Plants - Oklaunion Power Station
- --------------------------------------
In January 2004, TCC signed an agreement to sell its 7.81% share of
Oklaunion Power Station for approximately $43 million (subject to
closing adjustments) to an unrelated party. In May 2004, TCC received
notice from the two unaffiliated co-owners of the Oklaunion Power
Station, announcing their decision to exercise their right of first
refusal, with terms similar to the original agreement. In June 2004 and
September 2004, TCC entered into sales agreements with both of its
unaffiliated co-owners for the sale of TCC's 7.81% ownership of the
Oklaunion Power Station. One of these agreements is currently being
challenged in Dallas County, Texas State District Court by the unrelated
party with which TCC entered into the original sales agreement. The
unrelated party alleges that one co-owner has exceeded its legal
authority and that the second co-owner did not exercise its right of
first refusal in a timely manner. The unrelated party has requested that
the court declare the co-owners' exercise of their rights of first
refusal void. TCC cannot predict when these issues will be resolved. TCC
does not expect the sale to have a significant effect on its results of
operations. TCC's assets and liabilities related to the Oklaunion Power
Station have been classified as Assets Held for Sale - Texas Generation
Plants and Liabilities Held for Sale - Texas Generation Plants,
respectively, in TCC's Consolidated Balance Sheets at September 30, 2004
and December 31, 2003.
Texas Plants - South Texas Project
- ----------------------------------
In February 2004, TCC signed an agreement to sell its 25.2% share of the
South Texas Project (STP) nuclear plant to an unrelated party for
approximately $333 million, subject to closing adjustments. In June
2004, TCC received notice from co-owners of their decisions to exercise
their rights of first refusal, with terms similar to the original
agreement. In September 2004, TCC entered into sales agreements with two
of its unaffiliated co-owners for the sale of TCC's 25.2% share of the
STP nuclear plant. TCC does not expect the sale to have a significant
effect on its results of operations. TCC expects the sale to close in
the first six months of 2005. TCC's assets and liabilities related to
STP have been classified as Assets Held for Sale - Texas Generation
Plants and Liabilities Held for Sale - Texas Generation Plants,
respectively, in TCC's Consolidated Balance Sheets at September 30, 2004
and December 31, 2003.
The assets and liabilities of the TCC plants held for sale at September
30, 2004 and December 31, 2003 are as follows:
September 30, 2004 December 31, 2003
------------------ -----------------
(in millions)
Assets:
Other Current Assets $24 $57
Property, Plant and Equipment, Net 398 797
Regulatory Assets 53 49
Decommissioning Trusts 134 125
----- -------
Total Assets Held for Sale $609 $1,028
===== =======
Liabilities:
Regulatory Liabilities $1 $9
Asset Retirement Obligations 231 219
----- -------
Total Liabilities Held for Sale $232 $228
===== =======
8. BENEFIT PLANS
-------------
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in
AEP sponsored U.S. qualified pension plans and nonqualified pension
plans. A substantial majority of employees are covered by either one
qualified plan or both a qualified and a nonqualified pension plan. In
addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
participate in other postretirement benefit plans sponsored by AEP to
provide medical and death benefits for retired employees in the U.S.
The following tables provide the components of AEP's net periodic
benefit cost (credit) for the plans for the three and nine months ended
September 30, 2004 and 2003:
Three Months ended September 30, 2004 and 2003:
U.S.
U.S. Other Postretirement
Pension Plans Benefit Plans
--------------------- ------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Service Cost $22 $20 $10 $10
Interest Cost 57 58 29 33
Expected Return on Plan Assets (73) (79) (20) (16)
Amortization of Transition
(Asset) Obligation - (2) 7 7
Amortization of Net Actuarial Loss 4 3 9 13
---- ---- ---- ----
Net Periodic Benefit Cost (Credit) $10 $- $35 $47
==== ==== ==== ====
Nine Months ended September 30, 2004 and 2003:
U.S.
U.S. Other Postretirement
Pension Plans Benefit Plans
----------------------- -------------------------
2004 2003 2004 2003
------ ------ ------ -----
(in millions)
Service Cost $65 $60 $30 $31
Interest Cost 171 175 88 98
Expected Return on Plan Assets (219) (238) (61) (48)
Amortization of Transition
(Asset) Obligation 1 (6) 21 21
Amortization of Prior Service Cost - (1) - -
Amortization of Net Actuarial Loss 12 8 27 39
----- ----- ----- -----
Net Periodic Benefit Cost (Credit) $30 $(2) $105 $141
===== ===== ===== =====
The following table provides the net periodic benefit cost (credit) for
the plans by the following AEP registrant subsidiaries for the three and
nine months ended September 30, 2004 and 2003:
Three Months ended September 30, 2004 and 2003:
U.S.
U.S. Other Postretirement
Pension Plans Benefit Plans
------------------ --------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
APCo $318 $(1,300) $6,446 $8,420
CSPCo (407) (1,350) 2,762 3,671
I&M 1,115 (203) 4,315 5,750
KPCo 143 (142) 740 1,011
OPCo (32) (1,655) 5,260 7,052
PSO 699 (73) 2,112 2,471
SWEPCo 901 254 2,100 2,566
TCC 747 (31) 2,536 3,238
TNC 338 152 1,070 1,469
Nine Months ended September 30, 2004 and 2003:
U.S.
U.S. Other Postretirement
Pension Plans Benefit Plans
------------------ --------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
APCo $953 $(3,900) $19,338 $25,261
CSPCo (1,220) (4,050) 8,287 11,013
I&M 3,345 (607) 12,945 17,249
KPCo 430 (424) 2,221 3,032
OPCo (94) (4,967) 15,779 21,156
PSO 2,096 (219) 6,336 7,413
SWEPCo 2,703 762 6,300 7,698
TCC 2,241 (93) 7,608 9,713
TNC 1,014 456 3,210 4,406
9. BUSINESS SEGMENTS
-----------------
All of AEP's registrant subsidiaries have one reportable segment. The
one reportable segment is a vertically integrated electricity
generation, transmission and distribution business except AEGCo, an
electricity generation business. All of the registrants' other
activities are insignificant. The registrant subsidiaries' operations
are managed on an integrated basis because of the substantial impact of
bundled cost-based rates and regulatory oversight on the business
process, cost structures and operating results.
10. FINANCING ACTIVITIES
--------------------
Long-term debt and other securities issued and retired during the first
nine months of 2004 were:
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in thousands) (%)
Issuances:
- ----------
APCo Senior Unsecured Notes $125,000 Variable 2007
CSPCo Installment Purchase Contracts 48,550 Variable 2038
CSPCo Installment Purchase Contracts 43,695 Variable 2038
PSO Installment Purchase Contracts 33,700 Variable 2014
PSO Senior Unsecured Notes 50,000 4.70 2009
SWEPCo Installment Purchase Contracts 53,500 Variable 2019
SWEPCo Installment Purchase Contracts 41,135 Variable 2011
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in thousands) (%)
Retirements:
- ------------
APCo First Mortgage Bonds 21,000 7.70 2004
APCo First Mortgage Bonds 45,000 7.125 2024
APCo Installment Purchase Contracts 40,000 5.45 2019
CSPCo First Mortgage Bonds 11,000 7.60 2024
CSPCo Installment Purchase Contracts 48,550 6.375 2020
CSPCo Installment Purchase Contracts 43,695 6.25 2020
I&M First Mortgage Bonds 30,000 7.20 2024
I&M First Mortgage Bonds 25,000 7.50 2024
I&M Senior Unsecured Notes 150,000 6.875 2004
OPCo Installment Purchase Contracts 50,000 6.85 2022
OPCo Notes Payable 3,000 6.27 2009
OPCo Notes Payable 4,390 6.81 2008
OPCo First Mortgage Bonds 10,000 7.30 2024
OPCo Senior Unsecured Notes 140,000 7.375 2038
OPCo Senior Unsecured Notes 100,000 6.75 2004
OPCo Senior Unsecured Notes 75,000 7.00 2004
PSO Notes Payable to Trust 77,320 8.00 2037
PSO Installment Purchase Contracts 1,000 5.90 2007
PSO Installment Purchase Contracts 33,700 4.875 2014
SWEPCo Installment Purchase Contracts 53,500 7.60 2019
SWEPCo Installment Purchase Contracts 12,290 6.90 2004
SWEPCo Installment Purchase Contracts 12,170 6.00 2008
SWEPCo Installment Purchase Contracts 17,125 8.20 2011
SWEPCo First Mortgage Bonds 80,000 6.875 2025
SWEPCo First Mortgage Bonds 40,000 7.75 2004
SWEPCo Notes Payable 5,122 4.47 2011
SWEPCo Notes Payable 2,250 Variable 2008
TCC Notes Payable to Trust 140,889 8.00 2037
TCC First Mortgage Bonds 6,195 6.625 2005
TCC Securitization Bonds 48,551 3.54 2005
TNC First Mortgage Bonds 24,036 6.125 2004
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in thousands) (%)
Defeasance:
- -----------
TCC First Mortgage Bonds $27,400 (a) 7.25 2004
TCC First Mortgage Bonds 65,763 (a) 6.625 2005
TCC First Mortgage Bonds 18,581 (a) 7.125 2008
(a) Trust fund assets for defeasance of First Mortgage Bonds of $100
million are included in Other Cash Deposits and $22 million in
Bond Defeasance Funds in TCC's Consolidated Balance Sheets at
September 30, 2004. Trust fund assets are restricted for exclusive
use in funding the interest and principal due on the First
Mortgage Bonds.
In addition to the transactions reported in the table above, the
following table lists intercompany issuances and retirements of debt due
to AEP:
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in thousands) (%)
Issuances:
- ----------
CSPCo Notes Payable $100,000 4.64 2010
KPCo Notes Payable 20,000 5.25 2015
OPCo Notes Payable 200,000 5.25 2015
OPCo Notes Payable 200,000 3.32 2006
SWEPCo Notes Payable 50,000 4.45 2010
Retirements:
- ------------
None.
Lines of Credit - AEP System
- ----------------------------
The AEP System uses a corporate borrowing program to meet the short-term
borrowing needs of its 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. Utility money pool participants include AEGCo, APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC (domestic utility
companies). In addition, the AEP System also funds, as direct borrowers,
the short-term debt requirements of other subsidiaries that are not
participants in the non-utility money pool for regulatory or operational
reasons. The AEP System Corporate Borrowing Program operates in
accordance with the terms and conditions outlined by the SEC. AEP has
authority from the SEC through March 31, 2006 for short-term borrowings
sufficient to fund the utility money pool and the non-utility money pool
as well as its own requirements in an amount not to exceed $7.2 billion.
The utility money pool participants' money pool activity and
corresponding SEC authorized limits for the first nine months of 2004
are described in the following table:
Maximum Loans Loans (Borrowings) to/from SEC Authorized
Maximum Borrowings from to Utility Utility Money Pool as of Short-Term Borrowing
Company Utility Money Pool Money Pool September 30, 2004 Limit
- ------- ------------------------ ------------- --------------------------- --------------------
(in thousands)
AEGCo $56,525 $- $(15,497) $125,000
APCo 172,423 32,575 23,779 600,000
CSPCo 29,687 184,962 158,371 350,000
I&M 216,528 16,625 (98,762) 500,000
KPCo 44,749 38,242 37,779 200,000
OPCo 81,862 297,136 232,212 600,000
PSO 145,619 20,076 (19,259) 300,000
SWEPCo 71,252 96,615 96,615 350,000
TCC 109,696 427,414 172,051 600,000
TNC 16,136 85,482 54,495 250,000
For the first nine months of 2004, the maximum and minimum interest
rates for funds borrowed from the utility money pool were 1.92% and
1.32%, respectively. For the first nine months of 2004, the maximum and
minimum interest rates for funds loaned to the utility money pool were
1.93% and 0.89%, respectively.
REGISTRANT SUBSIDIARIES' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
- ----------------------------------------------------------------------
The following is a combined presentation of certain components of the
registrant subsidiaries' management's discussion and analysis. The
information in this section completes the information necessary for
management's discussion and analysis of financial condition and results
of operations and is meant to be read with (i) Management's Financial
Discussion and Analysis, (ii) financial statements, and (iii) footnotes
of each individual registrant. The Registrants' Combined Management's
Discussion and Analysis section of the 2003 Annual Report should be read
in conjunction with this report.
Significant Matters
- -------------------
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 save 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.
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.
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, management cannot,
at this time, determine whether disallowances that may be applicable to
CenterPoint would be applicable to TCC. Management believes that TCC's recorded
regulatory assets are in compliance with Texas Legislation and TCC intends to
seek vigorously recovery of these amounts. If, however, management
determines that it is probable TCC cannot recover a portion of its
recorded net true-up regulatory asset of $1.5 billion, and management is
able to estimate the amount of such non-recovery, TCC 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 their evaluation of the
final CenterPoint decision, additional material disallowances are
possible.
In another matter before to 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 $33 million to $43 million depending on the final treatment of
consolidated tax savings and other remanded issues. TCC defended
vigorously the 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. CSPCo's and OPCo's 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 management 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.
Unit Power Agreements
- ---------------------
A unit power agreement between AEGCo and I&M (the I&M Power Agreement)
provides for the sale by AEGCo to I&M of all the power (and the energy
associated therewith) available to AEGCo at the Rockport Plant unless it
is sold to another utility. I&M is obligated, whether or not power is
available from AEGCo, to pay as a demand charge for the right to receive
such power (and as an energy charge for any associated energy taken by
I&M) such amounts, when added to amounts received by AEGCo from any
other sources, will be at least sufficient to enable AEGCo to pay all
its operating and other expenses, including a rate of return on the
common equity of AEGCo as approved by FERC. The I&M Power Agreement will
continue in effect until the expiration of the lease term of Unit 2 of
the Rockport Plant unless extended in specified circumstances.
Pursuant to an assignment between I&M and KPCo, and a unit power
agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and
the energy associated therewith) available to AEGCo from both units of
the Rockport Plant. KPCo has agreed to pay to AEGCo in consideration for
the right to receive such power the same amounts which I&M would have
paid AEGCo under the terms of the I&M Power Agreement for such
entitlement. The KPCo unit power agreement expires on December 31, 2004.
The agreement will be extended through December 7, 2022, subject to both
KPSC and FERC approval.
Litigation
- ----------
AEP subsidiaries continue to be involved in various litigation matters
as described in the "Significant Factors - Litigation" section of
Registrants' Combined Management's Discussion and Analysis in the 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 the 2003 Annual
Report, but may have a material impact on 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 the current litigation include disclosure related to
Potential Uninsured Losses.
Federal EPA Complaint and Notice of Violation
- ---------------------------------------------
See discussion of New Source Review Litigation under "Environmental
Matters".
Enron Bankruptcy
- ----------------
In 2002, certain subsidiaries of AEP 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 subsidiaries of AEP had open trading
contracts and trading accounts receivables and payables with Enron. In
addition, on June 1, 2001, AEP purchased Houston Pipe Line Company (HPL)
from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.
Enron Bankruptcy - Commodity trading settlement disputes - In September
2003, Enron filed a complaint in the Bankruptcy Court against AEPES
challenging AEP's offsetting of receivables and payables and related
collateral across various Enron entities and seeking payment of
approximately $125 million plus interest in connection with gas related
trading transactions. AEP has asserted its right to offset trading
payables owed to various Enron entities against trading receivables due
to several AEP subsidiaries. The parties are currently in non-binding
court-sponsored mediation.
In December 2003, Enron filed a complaint in the Bankruptcy Court
against AEPSC seeking approximately $93 million plus interest in
connection with a transaction for the sale and purchase of physical
power among Enron, AEP and Allegheny Energy Supply, LLC during November
2001. Enron's claim seeks to unwind the effects of the transaction. AEP
believes it has several defenses to the claims in the action being
brought by Enron. The parties are currently in non-binding
court-sponsored mediation.
Enron Bankruptcy - Summary - The amounts expensed in prior years in
connection with the Enron bankruptcy were based on an analysis of
contracts where AEP and Enron entities are counterparties, the
offsetting of receivables and payables, the application of deposits from
Enron entities and management's analysis of the HPL-related purchase
contingencies and indemnifications. As noted above, Enron has challenged
the offsetting of receivables and payables. Although management is
unable to predict the outcome of these lawsuits, it is possible that
their resolution could have an adverse impact on results of operations,
cash flows or financial condition.
Merger Litigation
- -----------------
In 2002, the U.S. Court of Appeals for the District of Columbia ruled
that the SEC failed to adequately explain that the June 15, 2000 merger
of AEP with CSW meets the requirements of the PUHCA and sent the case
back to the SEC for further review. Specifically, the court told the SEC
to revisit the basis for its conclusion that the merger met PUHCA requirements
that utilities be "physically interconnected" and confined to a "single area
or region." In August 2004, the SEC announced it would conduct hearings
on this issue. The hearing is scheduled for January 2005.
In its June 2000 approval of the merger, the SEC agreed with AEP that
the companies' systems are integrated because they have transmission
access rights to a single high-voltage line through Missouri and also
met the PUHCA's single region requirement. In its ruling, the appeals
court said that the SEC failed to support and explain its conclusions
that the interconnection and single region requirements are satisfied.
Management believes that the merger meets the requirements of the PUHCA
and expects the matter to be resolved favorably.
Texas Commercial Energy, LLP Lawsuit
- ------------------------------------
Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider
(REP), filed a lawsuit in federal District Court in Corpus Christi,
Texas, in July 2003, against AEP and four of its subsidiaries, including
TCC and TNC, certain unaffiliated energy companies and ERCOT. The action
alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made
against TCC and TNC, range from anticompetitive bidding to withholding
power. TCE alleges that these activities resulted in price spikes
requiring TCE to post additional collateral and ultimately forced it
into bankruptcy when it was unable to raise prices to its customers due
to fixed price contracts. The suit alleges over $500 million in damages
for all defendants and seeks recovery of damages, exemplary damages and
court costs. Two additional parties, Utility Choice, LLC and Cirro
Energy Corporation, have sought leave to intervene as plaintiffs
asserting similar claims. AEP and its subsidiaries filed a Motion to
Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. AEP and its subsidiaries filed a Motion to Dismiss the
amended complaint. In June 2004, the Court dismissed all claims against
AEP and its subsidiaries. TCE has appealed the trial court's decision to
the United States Court of Appeals for the Fifth Circuit.
Energy Market Investigations
- ----------------------------
AEP and other energy market participants received data requests,
subpoenas and requests for information from the FERC, the SEC, the PUCT,
the U.S. Commodity Futures Trading Commission (CFTC), the U.S.
Department of Justice and the California attorney general during 2002.
Management responded to the inquiries and provided the requested
information and has continued to respond to supplemental data requests
in 2003 and 2004.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES
in federal district court in Columbus, Ohio. The CFTC alleges that AEP
and AEPES provided false or misleading information about market
conditions and prices of natural gas in an attempt to manipulate the
price of natural gas in violation of the Commodity Exchange Act. The
CFTC seeks civil penalties, restitution and disgorgement of benefits.
AEP responded to the complaint in September 2004. In 2003, AEP recorded
a provision related to these matters. AEP has engaged in settlement
discussions with several agencies and is evaluating whether to conclude
settlements in order to put these investigations behind AEP even though
management believes the Company has meritorious legal positions and
defenses. If AEP elects to settle all matters, the payments could exceed
the 2003 provision and could have a material impact on our 2004 earnings
and cash flows.
SWEPCo Notice of Enforcement and Notice of Citizen Suit
- -------------------------------------------------------
On July 13, 2004, two special interest groups issued a notice of intent
to commence a citizen suit under the Clean Air Act for alleged
violations of various permit conditions in permits issued to SWEPCo's
Welsh, Knox Lee, and Pirkey plants. This notice was prompted by
allegations made by a terminated AEP employee. The allegations at the
Welsh Plant concern compliance with emission limitations on particulate
matter and carbon monoxide, compliance with a referenced design heat
input value, and compliance with certain reporting requirements. The
allegations at the Knox Lee Plant relate to the receipt of an
off-specification fuel oil, and the allegations at Pirkey Plant relate
to testing and reporting of volatile organic compound emissions. No
action can be commenced until 60 days after the date of notice.
On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ)
issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant
containing a summary of findings resulting from a compliance
investigation at the plant. The summary includes allegations concerning
compliance with certain recordkeeping and reporting requirements,
compliance with a referenced design heat input value in the Welsh
permit, compliance with a fuel sulfur content limit, and compliance with
emission limits for sulfur dioxide.
On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo
relating to the off-specification fuel oil deliveries at the Knox Lee
Plant. On August 30, 2004, TCEQ issued a Notice of Enforcement to SWEPCo
relating to the reporting of volatile organic compound emissions at the
Pirkey Plant.
SWEPCo has previously reported to the TCEQ, deviations related to the
receipt of off-specification fuel at Knox Lee, the volatile organic compound
emissions at Pirkey, and the referenced recordkeeping and reporting
requirements and heat input value at Welsh. SWEPCo is preparing additional
responses to the Notice of Enforcement and the notice from the special
interest groups. Management is unable to predict the timing of any
future action by TCEQ or the special interest groups or the effect of
such actions on results of operations, cash flows or financial
condition.
Carbon Dioxide Public Nuisance Claims
- -------------------------------------
On July 21, 2004, attorneys general from eight states and the
corporation counsel for the City of New York filed an action in federal
district court for the Southern District of New York against AEP, AEPSC
and four other unaffiliated governmental and investor-owned electric
utility systems. That same day, a similar complaint was filed in the
same court against the same defendants by the Natural Resources Defense
Counsel on behalf of two special interest groups. The actions allege
that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts
associated with global warming, and seek injunctive relief in the form
of specific emission reduction commitments from the defendants. In September
2004, the defendants, including AEP and AEPSC, filed a motion to dismiss the
lawsuits. Management believes the actions are without merit and intends to
defend vigorously against the claims.
Environmental Matters
- ---------------------
As discussed in the 2003 Annual Report, there are emerging environmental
control requirements that management expects will result in substantial
capital investments and operational costs. The sources of these future
requirements include:
o Legislative and regulatory proposals to adopt stringent controls on
sulfur dioxide (SO2), nitrogen oxide (NOx) and mercury emissions from
coal-fired power plants,
o New Clean Water Act rules to reduce the impacts of water intake
structures on aquatic species at certain of our power plants, and
o Possible future requirements to reduce carbon dioxide emissions to
address concerns about global climatic change.
This discussion updates certain events occurring in 2004. You should
also read the "Significant Factors - Environmental Matters" section
within Registrants' Combined Management's Discussion and Analysis in the
2003 Annual Report for a description of all material environmental
matters affecting us, including, but not limited to, (1) the current air
quality regulatory framework, (2) estimated air quality environmental
investments, (3) Superfund and state remediation, (4) global climate
change, and (5) costs for spent nuclear fuel disposal and
decommissioning.
Future Reduction Requirements for SO2, NOx, and Mercury
- -------------------------------------------------------
In 1997, the Federal EPA adopted new, more stringent national ambient
air quality standards for fine particulate matter and ground-level
ozone. The Federal EPA is in the process of developing final
designations for fine particulate matter non-attainment areas. The
Federal EPA finalized designations for ozone non-attainment areas on
April 15, 2004. On the same day, the Administrator of the Federal EPA
signed a final rule establishing the elements that must be included in
state implementation plans (SIPs) to achieve the new standards, and
setting deadlines ranging from 2008 to 2015 for achieving compliance
with the final standard, based on the severity of non-attainment. All or
parts of 474 counties are affected by this new rule, including many
urban areas in the Eastern United States.
The Federal EPA identified SO2 and NOx emissions as precursors to the
formation of fine particulate matter. NOx emissions are also identified
as a precursor to the formation of ground-level ozone. As a result,
requirements for future reductions in emissions of NOx and SO2 from the
AEP System's generating units are highly probable. In addition, the
Federal EPA proposed a set of options for future mercury controls at
coal-fired power plants.
Regulatory Emissions Reductions
- -------------------------------
On January 30, 2004, the Federal EPA published two proposed rules that
would collectively require reductions of approximately 70% each in
emissions of SO2, NOx and mercury from coal-fired electric generating
units by 2015 (2018 for mercury). This initiative has two major
components:
o The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce
SO2 and NOx emissions across the eastern half of the United States
(29 states and the District of Columbia) and make progress toward
attainment of the new fine particulate matter and ground-level ozone
national ambient air quality standards. These reductions could also
satisfy these states' obligations to make reasonable progress towards
the national visibility goal under the regional haze program.
o The Federal EPA proposed to regulate mercury emissions from coal-fired
electric generating units.
The CAIR would require affected states to include, in their SIPs, a
program to reduce NOx and SO2 emissions from coal-fired electric utility
units. SO2 and NOx emissions would be reduced in two phases, which would
be implemented through a cap-and-trade program. Regional SO2 emissions
would be reduced to 3.9 million tons by 2010 and to 2.7 million tons by
2015. Regional NOx emissions would be reduced to 1.6 million tons by
2010 and to 1.3 million tons by 2015. Rules to implement the SO2 and NOx
trading programs were proposed on June 10, 2004.
On April 15, 2004, the Federal EPA Administrator signed a proposed rule
detailing how states should analyze and include "Best Available
Retrofit" requirements for individual facilities in their SIPs to
address regional haze. The guidance applies to facilities built between
1962 and 1977 that emit more than 250 tons per year of certain regulated
pollutants in specific industrial categories, including utility boilers.
The Federal EPA included an alternative "Best Available Retrofit"
program based on emissions budgeting and trading programs. For utility
units that are affected by the CAIR, described above, the Federal EPA
proposed that participation in the trading program under the CAIR would
satisfy any applicable "Best Available Retrofit" requirements. However,
the guidance preserves the ability of a state to require site-specific
installation of pollution control equipment through the SIP for purposes
of abating regional haze.
To control and reduce mercury emissions, the Federal EPA published two
alternative proposals. The first option requires the installation of
maximum achievable control technology (MACT) on a site-specific basis.
Mercury emissions would be reduced from 48 tons to approximately 34 tons
by 2008. The Federal EPA believes, and the industry concurs, that there
are no commercially available mercury control technologies in the
marketplace today that can achieve the MACT standards for bituminous
coals, but certain units have achieved comparable levels of mercury
reduction by installing conventional SO2 (scrubbers) and NOx (SCR)
emission reduction technologies. The proposed rule imposes significantly
less stringent standards on generating plants that burn sub-bituminous
coal or lignite. The proposed standards for sub-bituminous coals
potentially could be met without installation of mercury control
technologies.
The Federal EPA recommends, and AEP supports, a second mercury emission
reduction option. The second option would permit mercury emission
reductions to be achieved from existing sources through a national
cap-and-trade approach. The cap-and-trade approach would include a
two-phase mercury reduction program for coal-fired utilities. This
approach would coordinate the reduction requirements for mercury with
the SO2 and NOx reduction requirements imposed on the same sources under
the CAIR. Coordination is significantly more cost-effective because
technologies like scrubbers and SCRs, which can be used to comply with
the more stringent SO2 and NOx requirements, have also proven effective
in reducing mercury emissions on certain coal-fired units that burn
bituminous coal. The second option contemplates reducing mercury
emissions from 48 tons to 34 tons by 2010 and to 15 tons by 2018. A
supplemental proposal including unit-specific allocations and a
framework for the emissions budgeting and trading program preferred by
the Federal EPA was published in the Federal Register on March 16, 2004.
AEP filed comments on both the initial proposal and the supplemental
notice in June 2004.
The Federal EPA's proposals are the beginning of a lengthy rulemaking
process, which will involve supplemental proposals on many details of
the new regulatory programs, written comments and public hearings,
issuance of final rules, and potential litigation. In addition, states
have substantial discretion in developing their rules to implement
cap-and-trade programs, and will have 18 months after publication of the
notice of final rulemaking to submit their revised SIPs. As a result,
the ultimate requirements may not be known for several years and may
depart significantly from the original proposed rules described here.
While uncertainty remains as to whether future emission reduction
requirements will result from new legislation or regulation, it is
certain under either outcome that AEP subsidiaries will invest in
additional conventional pollution control technology on a major portion
of their coal-fired power plants. Finalization of new requirements for
further SO2, NOx and/or mercury emission reductions will result in the
installation of additional scrubbers, SCR systems and/or the
installation of emerging technologies for mercury control. The cost of
such facilities could have an adverse effect on future results of
operations, cash flows and financial condition unless recovered from
customers.
New Source Review Litigation
- ----------------------------
Under the Clean Air Act (CAA), if a plant undertakes a major
modification that directly results in an emissions increase, permitting
requirements might be triggered and the plant may be required to install
additional pollution control technology. This requirement does not apply
to activities such as routine maintenance, replacement of degraded
equipment or failed components, or other repairs needed for the
reliable, safe and efficient operation of the plant.
The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo
and other unaffiliated utilities modified certain units at coal-fired
generating plants in violation of the new source review requirements of
the CAA. The Federal EPA filed its complaints against AEP subsidiaries
in U.S. District Court for the Southern District of Ohio. The court also
consolidated a separate lawsuit, initiated by certain special interest
groups, with the Federal EPA case. The alleged modifications relate to
costs that were incurred at the generating units over a 20-year period.
On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in
order to "perfect" its complaint in the pending litigation. The NOV
expands the number of alleged "modifications" undertaken at the Amos,
Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek
plants during scheduled outages on these units from 1979 through the
present. Approximately one-third of the allegations in the NOV are
already contained in allegations made by the states or the special
interest groups in the pending litigation. The Federal EPA filed a
motion to amend its complaints and to expand the scope of the pending
litigation. The AEP subsidiaries opposed that motion. In September 2004,
the judge disallowed the addition of claims to the pending case. The
judge also granted motions to dismiss a number of allegations in the
original filing.
Management is unable to estimate the loss or range of loss related to
any contingent liability the AEP subsidiaries might have for civil
penalties under the CAA proceedings. Management is also unable to
predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be
determined by the Court. If the AEP System companies do not prevail, any
capital and operating costs of additional pollution control equipment
that may be required, as well as any penalties imposed, would adversely
affect future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated rates and
market prices for electricity.
In September 2004, the Sierra Club filed a complaint under the citizen
suit provisions of the CAA in the United States District Court for the
Southern District of Ohio alleging that violations of the PSD and New
Source Performance Standards requirements of the CAA and the opacity
provisions of the Ohio state implementation plan occurred at the J.M.
Stuart Station, and seeking injunctive relief and civil penalties.
Stuart Station is jointly owned by CSPCo (26%) and two unaffiliated
utilities. Management believes the allegations in the complaint are without
merit, and intend to defend vigorously this action. Management is unable
to predict the timing of any future action by the special interest group
or the effect of such actions on future operations or cash flows.
Clean Water Act Regulation
- --------------------------
On July 9, 2004, the Federal EPA published in the Federal Registrar a
rule pursuant to the Clean Water Act that will require all large
existing, once-through cooled power plants to meet certain performance
standards to reduce the mortality of juvenile and adult fish or other
larger organisms pinned against a plant's cooling water intake screens.
All plants must reduce fish mortality by 80% to 95%. A subset of these
plants that are located on sensitive water bodies will be required to
meet additional performance standards for reducing the number of smaller
organisms passing through the water screens and the cooling system.
These plants must reduce the rate of smaller organisms passing through
the plant by 60% to 90%. Sensitive water bodies are defined as oceans,
estuaries, the Great Lakes, and small rivers with large plants. These
rules will result in additional capital and operation and maintenance
expenses to ensure compliance. The estimated capital cost of compliance
for the AEP System's facilities, based on the Federal EPA's analysis in
the rule, is $193 million. Any capital costs associated with compliance
activities to meet the new performance standards would likely be
incurred during the years 2008 through 2010. Management has not
independently confirmed the accuracy of the Federal EPA's estimate. The
rule has provisions to limit compliance costs. Management may propose
less costly site-specific performance criteria if compliance cost
estimates are significantly greater than the Federal EPA's estimates or
greater than the environmental benefits. The rule also allows for
mitigation (also called restoration measures) if it is less costly and
has equivalent or superior environmental benefits than meeting the
criteria in whole or in part. Several states, electric utilities
(including APCo) and environmental groups appealed certain aspects of
the rule. Management cannot predict the outcome of the appeals. The
following table shows the investment amount per subsidiary.
Estimated
Compliance
Investments
-----------
(in millions)
APCo $21
CSPCo 19
I&M 118
OPCo 31
Other Matters
- -------------
As discussed in the 2003 Annual Report, there are several "Other
Matters" affecting AEP subsidiaries. The current status of FERC's market
power mitigation efforts is described below.
FERC Market Power Mitigation
- ----------------------------
In April 2004, the FERC issued two orders concerning utilities' ability
to sell wholesale electricity at market-based rates. In the first order,
the FERC adopted two new interim screens for assessing potential
generation market power of applicants for wholesale market based rates,
and described additional analyses and mitigation measures that could be
presented if an applicant does not pass one of these interim screens.
These two screening tests include a "pivotal supplier" test which
determines if the market load can be fully served by alternative
suppliers and a "market share" test which compares the amount of surplus
generation at the time of the applicant's minimum load. In July 2004,
the FERC issued an order on rehearing affirming its conclusions in the
April order and directing AEP and two unaffiliated utilities to file
generation market power analyses within 30 days. In the second order,
the FERC initiated a rulemaking to consider whether the FERC's current
methodology for determining whether a public utility should be allowed
to sell wholesale electricity at market-based rates should be modified
in any way.
On August 9, 2004, AEP submitted its Market Power Analysis pursuant to
the FERC's Orders on Rehearing. The analysis focused on the three major
areas in which AEP serves load and owns generation resources -- ECAR,
SPP and ERCOT, and the "first tier" control areas for each of those
areas.
The pivotal supplier and market share screen analyses that AEP filed
demonstrated that AEP does not possess market power in any of the
control areas to which it is directly connected (first-tier markets).
AEP passed both screening tests in all of its "first tier" markets. In
its three "home" control areas, AEP easily passed the pivotal supplier
test. AEP, as part of PJM, also passes the market share screen for the
PJM destination market. AEP also passed the market share screen for
ERCOT. AEP did not pass the market share screen as designed by the FERC
for the SPP control area. Consequently, AEP also submitted substantial
additional information, including historical purchase and sales data
that demonstrates that AEP does not possess market power in any of the
"home" destination markets. AEP requested that its existing market-based
pricing authorization in all markets be continued based on this
analysis. AEP also requested that the FERC rule without instituting a
proceeding and without setting a refund date. This case is pending.
CONTROLS AND PROCEDURES
-----------------------
During the third quarter of 2004, management, including the principal executive
officer and principal financial officer of AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC (collectively, the Registrants), evaluated the
Registrants' disclosure controls and procedures relating to the recording,
processing, summarization and reporting of information in the Registrants'
periodic reports filed with the SEC. These disclosure controls and procedures
have been designed to ensure that (a) material information relating to the
Registrants is made known to the Registrants' management, including these
officers, by other employees of the Registrants, and (b) this information is
recorded, processed, summarized, evaluated and reported, as applicable, within
the time periods specified in the SEC's rules and forms. The Registrant's
controls and procedures can only provide reasonable, not absolute, assurance
that the above objectives have been met.
As of September 30, 2004, these officers concluded that the disclosure controls
and procedures in place are effective and provide reasonable assurance that the
disclosure controls and procedures accomplished their objectives. The
Registrants continually strives to improve its disclosure controls and
procedures to enhance the quality of its financial reporting and to maintain
dynamic systems that change as events warrant.
There have been no changes in the Registrants' internal controls over financial
reporting (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the
Exchange Act) during the third quarter of 2004 that have materially affected, or
are reasonably likely to materially affect, the Registrants' internal control
over financial reporting.
PART II. OTHER INFORMATION
-----------------
Item 1. Legal Proceedings
-----------------
For a discussion of material legal proceedings, see Note 5,
Commitments and Contingencies, incorporated herein by reference.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
-----------------------------------------------------------
The following table provides information about purchases by AEP (or
its publicly-traded subsidiaries) during the quarter ended September
30, 2004 of equity securities that are registered by AEP (or its
publicly-traded subsidiaries) pursuant to Section 12 of the Exchange
Act:
ISSUER PURCHASES OF EQUITY SECURITIES
-------------------------------------
Maximum Number
(or Approximate
Total Number Dollar Value) of
of Shares Purchased as Shares that May Yet
Part of Publicly Be Purchased
Total Number of Average Price Announced Plans Under the Plans
Period Shares Purchased (1) Paid per Share or Programs or Programs
------ -------------------- -------------- ---------------------- --------------------
07/01/04 - 07/31/04 175 $65 - $-
08/01/04 - 08/31/04 - - - -
09/01/04 - 09/30/04 - - - -
--- --- --- ---
Total 175 $65 - $-
=== === === ===
(1) I&M repurchased an aggregate of 175 shares of its 4.12% cumulative
preferred stock, in a privately-negotiated transaction outside of an
announced program.
Item 5. Other Information
-----------------
NONE
Item 6. Exhibits
--------
AEP
*10(a) - Supplemental Retirement Savings Plan [Current Report on
Form 8-K, dated September 1, 2004, File No. 1-3525, Exhibit 99.1]
10(b) - Letter Agreement dated June 9, 2004 between AEPSC and
Carl English.
10(c) - Form of Performance Share Award Agreement
TCC
10(a) - Purchase and Sale Agreement by and between AEP Texas
Central Company and City of San Antonio (acting by and through
the City Public Service Board of San Antonio) and Texas Genco,
L.P., dated as of September 3, 2004.
OPCo
10(a) - Amendment No. 9, dated as of July 1, 2003 to Station
Agreement dated as of January 1, 1968, as amended, among OPCo,
Buckeye Power, Inc. and Cardinal Operating Company
AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
Exhibit 12 - Computation of Consolidated Ratio of Earnings to
Fixed Charges.
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
Exhibit 31.1 - Certification of Chief Executive Officer Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 31.2 - Certification of Chief Financial Officer Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.1 - Certification of Chief Executive Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the United States
Code.
Exhibit 32.2 - Certification of Chief Financial Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the United States
Code.
*Denotes exhibits incorporated by reference.
SIGNATURE
---------
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signature for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
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
SOUTHWESTERN ELECTRIC POWER COMPANY
By: /s/Joseph M. Buonaiuto
----------------------
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
Date: November 5, 2004