Back to GetFilings.com
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 JUNE 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
July 30, 2004 July 30, 2004
---------------- -------------
American Electric Power Company, Inc. 395,658,435 $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
June 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. Changes in Securities, Use of Proceeds and Issuer Purchases of
Equity Securities
Item 4. Submission of Matters to a Vote of Security Holders
Item 5. Other Information
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits: Exhibit 12 Exhibit 31.1
Exhibit 31.2 Exhibit 32.1 Exhibit
32.2
(b) Reports on Form 8-K O-4
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
---- -------
2004 True-up Proceeding A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount
of stranded costs and other true-up items and the recovery of such amounts.
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 generation
AEP Power Pool 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.
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.
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.
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.
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 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 the establishment of a regional
transmission structure.
o Accounting pronouncements periodically issued by accounting standard-setting
bodies.
o The performance of AEP's pension plan.
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
- ------------------
Divestiture Plans
- -----------------
As outlined in our 2003 Annual Report, we are continuing with our strategy of
disposing of various unregulated non-core businesses and assets in order to
focus management efforts on our core assets and operations and to eliminate
the negative earnings and cash consequences of these non-regulated operations.
We are also continuing the process of disposing of the generating assets of AEP
Texas Central Company (TCC) which will allow us to determine stranded costs for
recovery under Texas regulation.
During the first half of 2004, we (a) completed the sale of our interest in the
Pushan Power Plant, (b) closed on the sale of Louisiana Intrastate Gas Pipeline
Company and its approximately 2,000 miles of natural gas gathering and
transmission pipelines in Louisiana and five gas processing facilities that
straddle the system, and (c) completed the sale of assets, exclusive of certain
reserves and related liabilities, of the mining operations of AEP Coal. These
sales did not have a significant effect on our results of operations for the
second quarter 2004 or for the six months ended June 30, 2004.
In July 2004, we completed the sale of two coal-fired power plants in the U.K.
(Fiddler's Ferry in northwest England and Ferrybridge in northeast England),
related coal assets and a number of related commodities contracts. This sale
includes substantially all of our operations and assets in the Investments - UK
Operations segment. In July 2004, we also completed the sale of certain
generation assets within TCC, including eight natural gas plants, one coal-fired
plant and one hydro plant. We also closed on the sale of our ownership interests
in our two independent power producers in Florida and one in Colorado. We
anticipate the sale of our remaining independent power producer in Colorado will
be closed as soon as necessary regulatory approvals are obtained.
We are also making progress on the sale of our remaining TCC and non-core
assets. For TCC's assets, we have agreements for the sale of TCC's share of the
Oklaunion Power Station and TCC's share of the South Texas Project nuclear
plant. The co-owners of these facilities have notified TCC of their intentions
to exercise rights of first refusal, but we still expect to sell these assets
by the end of 2004. Nevertheless, there could be potential delays in receiving
necessary regulatory approvals and clearances which may delay the closings.
We also anticipate being able to reach an agreement for the sale of Jefferson
Island Storage and Hub, L.L.C., which holds the remaining LIG Pipeline Company
gas storage assets, by the end of the year.
We will continue to review our portfolio of businesses and assets for additional
divestiture opportunities which will further our goal of divesting of assets and
investments that are not a core part of our U.S. utility operations or are not
activities that will support or complement our regulatory utility business.
As indicated in our 2003 Annual Report, 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 six months ended June 30, 2004,
we reduced long-term debt by approximately $703 million. In July 2004, we
retired in excess of $500 million of additional long-term debt that we currently
do not plan to refinance, using cash on hand, proceeds from the issuance of
commercial paper and the net cash proceeds from the sale of certain Texas
generation assets. We anticipate further reductions of long-term debt over the
remainder of 2004. The result of our use of cash on hand and sales proceeds to
reduce debt has decreased our percentage of debt to total capitalization ratio
from 64.6% at December 31, 2003 to 63.3% at June 30, 2004.
Utility Operations
- ------------------
We continue to generate expected results from our Utility Operations as our net
income from Utility Operations was $183 million for the second quarter 2004 and
$486 million for the six-months ended June 30, 2004, although, these results are
not as strong when compared to the same periods in the prior year. Gross margins
improved in both periods driven by healthy utility sales increases in all
regions except Texas and improvements in the economy, but were more than offset
by increased expenses from outage maintenance and distribution system
reliability improvement work.
We made progress concerning regulatory challenges related to integration of the
AEP East companies into PJM (scheduled for October 1, 2004). A settlement
agreement was approved by the KPSC. A settlement was also reached with
interested parties in Virginia and is pending before the Virginia SCC for
approval. These settlements should allow the integration to proceed on time.
We announced during 2004 that we intend to invest approximately $3.5 billion on
environmental upgrades from 2004 to 2010 at our coal-fired generation plants in
order to continue our goal of producing low-cost electricity with minimal impact
on the environment. We continue to believe that investing in environmental
upgrades at existing plants is in the best interest of both our customers and
our business. Our commitment to make these investments is conditioned on
receiving appropriate recovery for our costs.
Texas Regulatory Activity
- -------------------------
The issue of stranded cost recovery in Texas continues to be a major focus for
us. At June 30, 2004, we have recorded net regulatory assets of approximately
$1.4 billion in stranded costs and other amounts that TCC will seek recovery of
in the true-up proceeding before the PUCT. We currently expect our stranded cost
filing to request recovery of amounts in excess of our related regulatory
assets. Although we believe that the regulatory assets that we have recorded are
appropriate, the ultimate outcome of the true-up proceeding before the PUCT
could have a negative effect on our future results of operations, cash flows and
financial condition.
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 moderate increase in our common stock dividend from its
current level of 35 cents per share per quarter.
Reorganization
- --------------
In addition to the significant changes occurring as a result of our divestiture
plan, we also recently reorganized and put in place a new management team that
will place increased emphasis on our energy delivery and distribution activities
through our existing operating companies which have been organized into seven
regions. As a consequence, we appointed seven regional presidents and their
respective teams. They are in place and operating as of the end of July. These
seven new regional presidents and their management teams will focus on
responding more quickly to the needs of our customers in their regions. This
change supports our long-term focus of creating stronger utility businesses,
more in touch with the local needs of customers and regulators.
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
- --------
AEP's 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 AEP's 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 were classified as discontinued
during 2003.
** UK Operations were classified as discontinued during 2003.
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 the gas pipeline
portion of Louisiana Intrastate Gas, and are currently marketing Jefferson
Island Storage & Hub, L.L.C., which holds the remaining Louisiana gas storage
assets held for sale. Upon completion of the divestiture of our non-core assets,
the only substantive portion of the Investments - Gas Operations business that
will remain is our Houston Pipe Line Company L.P. (HPL) operations, which
include the Bammel storage facility, and 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 this past
year including AEP Coal and our interest in the Pushan Power Plant. 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. We intend to
make decisions over the course of the remainder of the year which may lead to
changes in our reported business segments.
AEP Consolidated Results
- ------------------------
American Electric Power Company's consolidated Net Income for the three and six
month periods ended June 30, 2004 and 2003 was as follows (Earnings and Average
Shares Outstanding in millions):
Second Quarter Six Months Ended June 30,
-------------------------------------------- ---------------------------------------
2004 2003 2004 2003
---- ---- ---- ----
Earnings EPS Earnings EPS Earnings EPS Earnings EPS
-------- --- -------- --- -------- --- -------- ---
Utility Operations $183 $0.46 $225 $0.57 $486 $1.23 $531 $1.41
Investments - Gas Operations (4) (0.01) (25) (0.06) (13) (0.03) (43) (0.11)
Investments - UK Operations - - - - - - - -
Investments - Other (3) (0.01) (20) (0.05) 1 - - -
All Other* (25) (0.06) (3) (0.01) (34) (0.09) (18) (0.05)
----- ------ ----- ------ ----- ------ ----- ------
Income Before Discontinued Operations
and Cumulative Effect of Accounting
Changes 151 0.38 177 0.45 440 1.11 470 1.25
Investments - Gas Operations 2 - 1 - 1 - 4 0.01
Investments - UK Operations (52) (0.13) 4 0.01 (64) (0.16) (37) (0.09)
Investments - Other (1) - (7) (0.02) 5 0.01 (15) (0.04)
----- ------ ----- ------ ----- ------ ----- ------
Discontinued Operations (51) (0.13) (2) (0.01) (58) (0.15) (48) (0.12)
Utility Operations - - - - - - 236 0.63
Investments - Gas Operations - - - - - - (22) (0.06)
Investments - UK Operations - - - - - - (21) (0.06)
----- ------ ----- ------ ----- ------ ----- ------
Cumulative Effect of Accounting Changes - - - - - - 193 0.51
----- ------ ----- ------ ----- ------ ----- ------
Total Net Income $100 $0.25 $175 $0.44 $382 $0.96 $615 $1.64
===== ====== ===== ====== ===== ====== ===== ======
Average Shares Outstanding 396 395 396 376
=== === === ===
* All Other includes the parent company interest income and expense, as well as other non-allocated costs.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Income Before Discontinued Operations and Cumulative Effect of Accounting
Changes decreased $26 million to $151 million in 2004 compared to 2003. Net
Income for 2004 of $100 million or $0.25 per share includes a loss, net of
taxes, from discontinued operations of $51 million. Net Income for 2003 of $175
million or $0.44 per share includes a loss, net of taxes, from discontinued
operations of $2 million.
For the second quarter 2004 our Utility Operations Net Income decreased $42
million, or almost 19%, from the previous year driven by increased spending on
operations and maintenance expenses. Our UK Operations (which were sold on July
30, 2004) also contributed $56 million to the decrease in net income in the
second quarter 2004. Our Gas Operations and Other Investments segments posted
better results in 2004. Our Gas Operations segment benefited from increased
earnings from pipeline optimization and storage activities and lower operating
expenses, and our Investments - Other segment benefited from a reduction in our
provisions for uncollectible accounts receivable and lower overall expenses in
2004.
During the fourth quarter of 2003, we concluded that the UK Operations and LIG
were not part of our core business, and we began actively marketing each of
these investments for sale. The UK Operations consist of our generation and
trading operations that sell to wholesale customers and its coal procurement and
transportation operations. In July 2004, we completed the sale of substantially
all operations and assets within our Investments - UK Operations segment. LIG's
operations include 2,000 miles of intrastate gas pipelines, gas processing
facilities and a 9.7 billion cubic feet natural gas storage facility. LIG
Pipeline Company, which owned the pipeline and processing operations of LIG, was
sold in April 2004 (see Note 7).
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Income Before Discontinued Operations and Cumulative Effect of Accounting
Changes decreased $30 million to $440 million in 2004 compared to 2003. Net
Income for 2004 of $382 million or $0.96 per share includes a loss, net of
taxes, from discontinued operations of $58 million. Net Income for 2003 of $615
million or $1.64 per share includes a loss, net of taxes, from discontinued
operations of $48 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 six months ended June 30, 2004, Utility Operations Income Before
Discontinued Operations and Cumulative Effect of Accounting Changes decreased
$45 million or almost 8.5% from the previous year driven by increased spending
on operations and maintenance expenses. Our UK Operations (which were sold on
July 30, 2004) also were responsible for $6 million (including cumulative effect
of accounting changes) of the decrease in Net Income in 2004, while we sought a
buyer for our U.K. assets, all of which are part of discontinued operations. In
July 2004, we completed the sale of substantially all operations and assets
within our Investments - UK Operations segment. Our Investments-Gas Operations
segment posted a lower loss in 2004, benefiting from improved margins and
reductions in operating expenses.
Our results of operations by operating segment are discussed below.
Utility Operations
- ------------------
Second Quarter Six Months Ended June 30,
------------------------------ -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Revenues $2,544 $2,665 $5,149 $5,371
Fuel and Purchased Power 821 956 1,581 1,846
------- ------- ------- -------
Gross Margin 1,723 1,709 3,568 3,525
Depreciation and Amortization 308 315 618 610
Other Operating Expenses 998 889 1,911 1,760
------- ------- ------- -------
Operating Income 417 505 1,039 1,155
Other Income (Expense), Net 16 5 25 3
Interest Expense and Preferred
Stock Dividend Requirements 157 167 320 331
Income Tax Expense 93 118 258 296
------- ------- ------- -------
Income Before Discontinued
Operations and Cumulative Effect $183 $225 $486 $531
======= ======= ======= =======
Summary of Selected Sales Data
For Utility Operations
Second Quarter Six Months Ended June 30,
----------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
Energy Summary (in millions of KWH)
Retail
Residential 9,740 8,659 23,167 22,080
Commercial 9,390 8,773 18,169 17,568
Industrial 12,902 12,449 25,175 24,455
Miscellaneous 806 734 1,549 1,424
------- ------- ------- -------
Subtotal 32,838 30,615 68,060 65,527
Texas Retail and Other 262 739 486 1,538
------- ------- ------- -------
Total 33,100 31,354 68,546 67,065
======= ======= ======= =======
Wholesale 19,884 16,357 39,225 36,716
======= ======= ======= =======
Second Quarter Six Months Ended June 30,
----------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
Weather Summary (in degree days)
Eastern Region
- --------------
Actual - Heating 167 141 2,031 2,169
Normal - Heating* 180 ** 1,986 **
Actual - Cooling 313 157 316 158
Normal - Cooling* 278 ** 281 **
Western Region (PSO/SWEPCo)
- ---------------------------
Actual - Heating 30 34 913 1,074
Normal - Heating* 33 ** 1,012 **
Actual - Cooling 659 638 689 644
Normal - Cooling* 642 ** 660 **
* Normal Heating/Cooling represents the 30-year average of degree days.
**Not meaningful.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Income from Utility Operations decreased $42 million to $183 million in 2004.
The key driver of the decrease was a $109 million increase in other operating
expenses, partially offset by a $14 million increase in gross margin, a $25
million decrease in income taxes, and a $28 million net decrease in other
expenses.
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 $47 million. Residential demand increased over the prior year as
a consequence of higher usage by customers resulting from favorable weather.
Cooling degree days were up significantly in the East and off slightly in
the West. Heating degree days were up in the East and off slightly in the
West as compared to the prior year. Commercial and industrial demand also
increased resulting from the economic recovery in our regions.
o Fuel recovery in our non-Texas utility business was a net $37 million
favorable in comparison to last year primarily due to higher fuel costs
in the prior year resulting from the conclusion of the amortization of Cook
plant outage costs and a fish intrusion outage causing us to purchase higher
priced non-nuclear power in 2003.
o Our Texas supply business had a $31 million decrease in gross margin
principally due to a $52 million decrease resulting from increased
provisions for potential fuel disallowances in Texas, offset by a $21
million increase from a favorable adjustment recorded in 2004 to a retail
clawback refund related to the number of customers receiving price-to-beat
service in Texas.
o Beginning in 2004, the wholesale capacity auction true-up ceased per rules
of the PUCT, therefore revenues are no longer recognized, resulting in
$52 million of lower regulatory deferrals in 2004. For the years 2003 and
2002, we recognized the non-cash 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 $9 million better than 2003
due to favorable power and coal optimization activity, slightly offset by
lower volumes.
Utility operating expenses and income tax expense changed between years as
follows:
o Maintenance and Other Operation expense increased $89 million due to a $33
million increase from the timing of planned plant outages in 2004 as
compared to 2003, $29 million of increased distribution maintenance expense
primarily from storm damage and system reliability work, and a $14 million
net increase in employee-related benefits and insurance, magnified by
favorable adjustments in 2003. These increases were offset, in part, by
$10 million due to the conclusion of the amortization of our deferred Cook
nuclear plant restart settlement expenses. Expenses of $23 million,
comprised of several miscellaneous items, make up the remainder of the
increase.
o Income Tax Expense decreased $25 million almost entirely due to the
decrease in pre-tax income.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Income from Utility Operations, before $236 million of cumulative effect of
accounting changes in 2003, decreased $45 million to $486 million in 2004. Key
drivers of the change include a $151 million increase in Other Operating
Expenses, offset by a $43 million increase in gross margin, a $38 million
decrease in income taxes, a $22 million increase in net other income and a $3
million net decrease in other expense line items.
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 $63 million. Residential demand in the East increased over the
prior year as a consequence of higher usage by customers partially
resulting from favorable weather while demand in the West was off slightly.
Cooling degree days were up significantly in the East and up slightly in
the West. Heating degree days were off slightly in the East and off in the
West as compared to the prior year. Overall commercial and industrial
demand also increased resulting from the economic recovery in our regions.
o Fuel recovery in our non-Texas utility business was a net $59 million
favorable in comparison to last year primarily due to higher fuel costs in
the prior year resulting 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 $43 million decrease in gross margin
principally due to a $27 million decrease resulting from increased
provisions for potential fuel disallowances in Texas, a $31 million impact
from lower Reliability-Must-Run (RMR) contract margins, and a $16 million
unfavorable variance due to declining commercial and industrial business in
Texas, offset by a $21 million increase from a favorable adjustment recorded
in 2004 to a retail clawback refund related to the number of customers
receiving price-to-beat service in Texas.
o Beginning in 2004, the wholesale capacity auction true-up ceased per rules
of the PUCT, therefore revenues are no longer recognized, resulting in
$108 million of lower regulatory deferrals in 2004. For the years 2003 and
2002, we recognized the non-cash 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 $60 million better than in 2003
due to favorable power and coal optimization activity, slightly offset by
lower volumes.
Utility operating expenses and income tax expense changed between years as
follows:
o Maintenance and Other Operation expense increased $135 million due to a
$63 million increase from the timing of planned plant outages in 2004
as compared to 2003, $28 million of increased distribution maintenance
expense from system reliability work and a $30 million net increase in
employee-related benefits, insurance and other administrative expenses
magnified by favorable adjustments in 2003. These increases were offset,
in part, by $20 million due to the conclusion of the amortization of our
deferred Cook nuclear plant restart settlement expenses. Expenses of
$34 million, comprised of several miscellaneous items, make up the
remainder of the increase.
o The remaining $16 million of the increase in Other Operating Expenses was a
result of an increase in taxes other than income taxes.
o Income Tax Expense decreased $38 million due to the decrease in pre-tax
income and other tax return adjustments.
Investments - Gas Operations
- ----------------------------
Second Quarter Six Months Ended June 30,
--------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Revenue $817 $675 $1,468 $1,623
Purchased Gas 773 684 1,385 1,574
----- ----- ------- -------
Gross Margin 44 (9) 83 49
Maintenance and Other Operation 31 36 60 74
Other Operating Expense 3 6 6 11
----- ----- ------- -------
Operating Income (Loss) 10 (51) 17 (36)
Other Income (Expense), Net (3) 1 (9) (5)
Interest Expense 13 14 25 26
Income Tax Benefit 2 39 4 24
----- ----- ------- -------
Net Loss Before Discontinued Operations and
Cumulative Effect $(4) $(25) $(13) $(43)
===== ===== ======= =======
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Our $4 million loss from Gas Operations before discontinued operations and
cumulative effect of accounting changes compares with a $25 million loss
recorded in the second quarter of 2003. Gross margins improved $53 million
year-over-year driven by improvements in our earnings from pipeline optimization
and storage activities. Operating expenses decreased by $8 million as a result
of reduced gas trading activities and lower depreciation resulting from 2003
asset impairments. Income tax benefits decreased by $37 million due to the
improvement in pre-tax income and a $16 million tax benefit adjustment from a
capital loss recorded in the second quarter of 2003.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Our $13 million loss from Gas Operations before discontinued operations and
cumulative effect of accounting changes compares with a $43 million loss
recorded in the year-to-date June 2003 period. Gross margins improved $34
million year-to-date June 30, 2004 to $83 million. The increase in margins were
driven by $20 million of significant losses in 2003 from servicing a single
contract when gas prices were at an all time high, and $6 million higher
pipeline and pipeline optimization margins in 2004. In addition, operating
expenses decreased $19 million between periods due to reduced gas trading
activities and lower depreciation resulting from 2003 asset impairments. Income
tax benefits decreased by $20 million primarily due to the improvement in
pre-tax income.
Investments - UK Operations
- ---------------------------
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Our UK Operations (all classified as Discontinued Operations) incurred a loss of
$52 million for 2004 compared with income of $4 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.
Our UK Operations' gross margins from generation increased $11 million in 2004,
reflecting the improvement in wholesale electricity prices in the U.K. These
improvements were offset by a $32 million decrease in margins from risk
management activity primarily resulting from AEP's decision to exit trading in
the first quarter of 2004 and the closure and settlement of non-core and
residual positions, as well as an increase of $37 million in maintenance and
other operation expense due to several factors, including the expensing of
capital expenditures during held-for-sale status to maintain the appropriate
fair value of the fixed assets and higher connection charges resulting from a
re-zoning of the plants.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Our UK Operations (all classified as Discontinued Operations) incurred a loss of
$64 million for 2004 compared with a loss of $37 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.
Our UK Operations' gross margins from generation increased $40 million as a
result of a 4% increase in generation and favorable price variances. Risk
management margin was lower by $63 million resulting from AEP exiting trading in
the first quarter of 2004 and the closure and settlement of non-core and
residual positions. Operating expenses were unfavorable by $33 million due to
several factors, including the expensing of capital expenditures during the
held-for-sale status to maintain the appropriate fair value of the fixed assets
and higher connection charges resulting from a re-zoning of the plants.
Depreciation and amortization decreased $10 million due to the cessation of
plant depreciation due to the held-for-sale status of assets.
Investments - Other
- -------------------
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Loss before discontinued operations and cumulative effect of accounting changes
from our Investments - Other segment decreased by $17 million to $3 million in
2004.
The decrease in the loss is due to the following:
(a) Our AEP Texas Provider of Last Resort (POLR) entity recorded a $6
million provision for uncollectible receivables in the second quarter
2003 that did not reoccur in 2004,
(b) Our AEP Resources entity decreased its loss by $7 million in the second
quarter 2004 as compared to 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
(c) Our AEP Pro Serv entity reduced losses from $4 million to break even,
primarily due to operations winding down in 2004.
In addition to the items above, the results from our IPPs and windfarms
decreased $3 million primarily driven by an additional $1.6 million impairment
recorded by one of our Colorado IPPs in June 2004 and an additional $1 million
of expense related to unfavorable unit outages at our Mulberry unit in Florida
and maintenance at our Sweeney unit in Texas. These decreases of $3 million
were equally offset by other insignificant increases at other investment
entities.
In discontinued operations, Eastex was sold in the third quarter 2003 and Pushan
Power Plant was sold in March 2004.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Income before discontinued operations and cumulative effect of accounting
changes from our Investments - Other segment increased from no income to $1
million of income in 2004.
The key components of the increase in income were as follows:
(a) 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 reoccur in 2004,
(b) Our AEP Resources entity decreased their loss by $17 million for the
first six months of 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,
(c) Our AEP Pro Serv entity reduced losses from $4 million to break even,
primarily due to operations winding down in 2004, and
(d) Our other entities had individually insignificant changes in results
totaling a net $5 million increase in income between years.
Offsetting these increases was a $31 million nonrecurring gain recorded in the
first quarter of 2003 primarily related to a gain from the sale of Mutual
Energy.
In discontinued operations, Eastex was sold in the third quarter 2003 and Pushan
Power Plant was sold in March 2004.
All Other
- ---------
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Our parent company's second quarter 2004 expenses increased $22 million over the
second quarter 2003 resulting primarily from a $6 million decrease in interest
income generated from a lower average intercompany debt receivable balance and
lower net invested cash during the quarter, a $7 million increase in interest
expense resulting primarily from accelerated discount amortization from the
early redemption of senior notes in May 2004, a $2 million decrease in parent
guarantee fee income, and an additional net $7 million increase in other
expenses, none individually significant.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Our parent company's year-to-date 2004 expenses increased $16 million over the
year-to-date 2003 time period primarily due to a $17 million decrease in
interest income generated from a lower average intercompany debt receivable
balance and lower net invested cash during the six months in 2004, a $3 million
decrease in parent guarantee fee income, and a $2 million increase in other
expenses, partially offset by a $6 million decrease in operations and
maintenance expense resulting from lower general advertisement expenses in 2004.
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were 34.1% and
24.7%, respectively. The increase in the effective tax rate is primarily due to
realizing a tax benefit from a capital loss in the second quarter of 2003. The
difference in the effective income tax rate and the federal statutory rate of
35% is due to flow-through of book versus tax differences, permanent
differences, energy production credits, amortization of investment tax credits
and state income taxes.
The effective tax rates for the first six months of 2004 and 2003 were 35.3% 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
differences, permanent differences, energy production credits, amortization of
investment tax credits and state income taxes. The effective tax rates remained
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
- --------------
June 30, December 31,
2004 2003
-------- ------------
Common Equity 36.4% 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 60.3 62.8
Short-term Debt 2.7 1.5
------ ------
Total Capitalization 100.0% 100.0%
====== ======
Our $1.3 billion in cash flows from operations, combined with our reduction in
cash expenditures for investments in discontinued operations, a second quarter
of 2003 reduction in dividends paid and the use of a portion of our cash on
hand, allowed us to reduce long-term debt by $703 million, while only increasing
short-term debt by $270 million. Our common equity percentage benefited from the
issuance of $11 million of new common equity (related to our incentive
compensation plans) and the fact that our earnings exceeded our dividends for
the six months ended June 30, 2004. As a consequence of the capital changes
during the six months, we improved our ratio of debt to total capital from
64.6% to 63.3% (preferred stock subject to mandatory redemption is included in
debt component of ratio).
In July 2004, we retired in excess of $500 million of long-term debt that we
currently do not plan to refinance, using cash on hand, proceeds from the
issuance of commercial paper and a portion of the net cash proceeds from the
sale of certain Texas generation assets.
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 June 30, 2004, of approximately $3.4
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
Euro Revolving Credit
Facility 184 October 2004
Letter of Credit Facility 200 September 2006
------
Total 3,134
Cash and Cash Equivalents 858
------
Total Liquidity Sources 3,992
Less: AEP Commercial Paper
Outstanding 554(a)
Letters of Credit
Outstanding 52
------
Net Available Liquidity at June 30, 2004 $3,386
======
(a) Amount does not include JMG Funding LP commercial paper outstanding
in the amount of $21 million. This commercial paper is specifically
associated with the Gavin scrubber lease and does not reduce available
liquidity to AEP.
Debt Covenants and Borrowing Limitations
- ----------------------------------------
Our revolving credit agreements 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
June 30, 2004, we were in compliance with the covenants contained in these
credit agreements and debt to total capitalization was 58.0%. 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 thereunder 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 June 30, 2004, we were in compliance with this order.
Money pool and external borrowings may not exceed SEC or state commission
authorized limits. At June 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 plans during
2004 to further reduce our outstanding debt through the use of proceeds from our
planned dispositions and the use of cash on hand. Our ratings have not been
adjusted by any rating agency during 2004. On August 2, 2004, Moody's Investors
Service (Moody's) changed their ratings 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 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 moderate increase in our common stock dividend from
its current level of 35 cents per share per quarter.
Cash Flow
- ---------
Our cash flows are a major factor in managing and maintaining our liquidity
strength.
Six Months Ended June 30,
2004 2003
---- ----
(in millions)
Cash and Cash Equivalents at Beginning of Period $976 $1,088
------ -------
Net Cash Flows From Operating Activities 1,262 850
Net Cash Flows Used For Investing Activities (575) (1,288)
Net Cash Flows From (Used For) Financing Activities (805) 420
------ -------
Net Decrease in Cash and Cash Equivalents (118) (18)
------ -------
Cash and Cash Equivalents at End of Period $858 $1,070
====== =======
In addition to cash on hand, 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 June 30, 2004, we
had credit facilities totaling $2.75 billion to support our commercial paper
program. At June 30, 2004, AEP had $596 million outstanding in short-term
borrowings of which $554 million was commercial paper supported by the revolving
credit facilities. In addition, JMG had commercial paper outstanding in the
amount of $21 million. This commercial paper is specifically associated with the
Gavin scrubber lease and is not supported by our credit facilities. The maximum
amount of AEP commercial paper outstanding during the quarter ended June 30,
2004 was $661 million. The weighted-average interest rate for our commercial
paper during the second quarter 2004 was 1.42%.
We generally use short-term borrowings to fund working capital needs, property
acquisitions and construction until long-term funding mechanisms 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
- --------------------
Six Months Ended June 30,
2004 2003
---- ----
(in millions)
Net Income $382 $615
Plus: Losses from Discontinued Operations 58 48
------- ----
Income from Continuing Operations 440 663
Noncash Items Included in Earnings 766 462
Changes in Assets and Liabilities 56 (275)
------- -----
Net Cash Flows From Operating Activities $1,262 $850
======= =====
2004 Operating Cash Flow
- ------------------------
Our cash flows from operating activities were $1,262 million for the first six
months of 2004. We produced income from continuing operations of $440 million
during the period. Income from continuing operations for the period included
noncash expense items of $716 million for depreciation, amortization and
deferred taxes. In addition, there is a current period impact for a net $50
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
$196 million, and an increase in the balance of accrued taxes of $140 million.
2003 Operating Cash Flow
- ------------------------
Our cash flows from operating activities were $850 million for the first six
months of 2003. We produced income from continuing operations of $663 million
during the period. Income from continuing operations for the period included
noncash items of $668 million for depreciation, amortization, and deferred
taxes, and $193 million related to the cumulative effect of accounting changes.
There was a current period impact for a net $33 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. The other activity in
the asset and liability accounts related to the wholesale capacity auction
true-up asset (ECOM) of $108 million, increases in customer deposits and risk
management collateral of $167 million, increases in accrued taxes of $62 million
and changes in accounts receivable and accounts payable of $145 million.
Investing Activities
- --------------------
Six Months Ended June 30,
2004 2003
---- ----
(in millions)
Construction Expenditures $(697) $(639)
Change in Other Cash Deposits, Net (2) 23
Investment in Discontinued Operations, net - (716)
Proceeds from Sale of Assets 131 41
Other (7) 3
------ --------
Net Cash Flows Used for Investing Activities $(575) $(1,288)
====== ========
Our cash flows used for investing activities decreased $713 million from the
same period in the prior year primarily due to investments made in our U.K.
operations during 2003 that did not recur during 2004.
Financing Activities
- --------------------
Six Months Ended June 30,
2004 2003
---- ----
(in millions)
Issuances of Common Stock $11 $1,142
Issuances/Retirements of Debt, net (535) (153)
Retirement of Preferred Stock (4) (2)
Retirement of Minority Interest - (225)
Dividends (277) (342)
------ -------
Net Cash Flows From (Used for)
Financing Activities $(805) $420
====== =======
Our cash flow from financing activities in 2004 decreased $1.2 billion from the
$420 million net cash inflow recorded in 2003. During the first quarter of 2003,
we issued common stock for $1,142 million and subsequent to the first quarter of
2003, we reduced our dividend. This compares to only $11 million of cash
proceeds from the issuance of common stock under our incentive compensation
plans in the first six months of 2004.
During the first six months of 2004, we used approximately $986 million of cash
to retire long-term debt. We also issued approximately $268 million of long-term
debt ($263 million net of issuance costs) including $173 million of pollution
control bonds (installment purchase contracts). These activities were supported
by the generation of $1.3 billion in cash flow from operations. See Note 10
"Financing Activities" for further information regarding issuances and
retirements of debt instruments during the first six months of 2004.
Off-balance Sheet Arrangements
- ------------------------------
In prior years, we entered into off-balance sheet arrangements for various
reasons including accelerating cash collections, reducing operational expenses
and spreading risk of loss to third parties. Our off-balance sheet arrangements
have not changed significantly from year-end 2003 and are comprised of a sale
of receivables agreement maintained by AEP Credit, a sale and leaseback
transaction entered into by AEGCo and I&M with an unrelated unconsolidated
trustee, and an agreement with an unrelated, unconsolidated leasing company to
lease coal-transporting aluminum railcars. 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 into in the normal course of business. 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 June 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 (1.61% as of June 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 upon 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 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
- -------------------
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 independent power producers (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 January 2004 that we had signed an agreement to sell TCC's
7.81% share of the Oklaunion Power Station for approximately $43 million,
subject to closing adjustments, (2) announcing in February 2004 that we had
signed an agreement to sell TCC's 25.2% share of the South Texas Project nuclear
plant for approximately $333 million, subject to closing adjustments, and (3)
closing on the sale of TCC's remaining generation assets, including eight
natural gas plants, one coal-fired plant and one hydro plant for approximately
$425 million, net of adjustments. Subject to certain issues that have arisen
relating to co-owners' rights of first refusal, we expect the sales of TCC's
shares of Oklaunion and South Texas Project to close before the end of 2004.
There could, however, be potential delays in receiving necessary regulatory
approvals and clearances which may delay the closing. The sale of TCC's
remaining generation assets was completed in July 2004. We will file with the
PUCT to recover net stranded costs associated with each of the sales pursuant to
Texas restructuring legislation.
AEP Coal
- --------
As a result of management's decision to exit our non-core businesses, we
retained an advisor in 2003 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. The sale closed in
April 2004 and the effect of the sale on second quarter 2004 results of
operations was not significant.
Gas Operations
- --------------
During the third quarter of 2003, management hired advisors to review business
options regarding various investment components of our Investments-Gas
Operations segment. 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. 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. We continue to market Jefferson
Island Storage & Hub, L.L.C., the remaining LIG gas storage entity, and
anticipate the sale before the end of 2004.
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 declines in fair
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
(recorded in Maintenance and Other Operation expense) 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
approximately $100 million, generated primarily from the sale of the two Florida
IPPs which were not originally impaired. The gain was recorded during July 2004.
The sale of the Ft. Lupton, Colorado plant is awaiting FERC approval and is
expected to close during the third quarter 2004, with no significant effect on
results of operations during the third 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 assets, and a number of related commodities contracts. We are still
determining the final impact from the sale on our third quarter 2004 results of
operations. Although the final sales price will be subject to closing
adjustments, expected to be determined during the third quarter 2004, we
believe that a gain on sale, which would be included in discontinued operations,
may result.
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.
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.
The status of the transfer of functional control of our subsidiaries'
transmission systems to RTOs or the status of our participation in RTOs has not
changed significantly from our disclosure as described in "RTO Formation" within
the "Management's Financial Discussion and Analysis of Results of Operations"
section of the 2003 Annual Report.
In November 2003, the FERC preliminarily found that we must fulfill our CSW
merger condition to join an RTO by integrating into PJM (transmission and
markets) by October 1, 2004. FERC based their order on PURPA 205(a), which
allows FERC to exempt electric utilities from state law or regulation in certain
circumstances. An ALJ held hearings on issues including whether the laws, rules,
or regulations of Virginia and Kentucky prevent us 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 a final order in June
2004.
In April 2004, we reached an agreement with interveners to settle the RTO issues
in Kentucky. The KPSC approved the settlement agreement in May 2004 and the FERC
approved the settlement in June 2004.
In July 2004, we reached an agreement with the intervenors to settle the RTO
issues in Virginia. The settlement agreement is now subject to approval by the
Virginia SCC.
If the Virginia settlement is approved, it should allow our AEP East companies
to join PJM and address state concerns without any significant expected adverse
impacts on future results of operations.
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.
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 six months of 2004, that should be read in order to gain a full
understanding of our current litigation include: (1) Bank of Montreal Claim, (2)
Shareholders' Litigation, (3) Cornerstone Lawsuit, and (4) 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.
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 proposed settlement is subject to
Bankruptcy Court approval. 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.
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.
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 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.
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. Management is unable to predict the outcome
of these lawsuits or their impact on our results of operations, cash flows or
financial condition.
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 AEP 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. In January 2004, the CFTC issued a request for
documents and other information in connection with a CFTC investigation of
activities affecting the price of natural gas in the fall of 2003. We responded
to that request. The case is in the initial pleading stage with our response to
the complaint currently due on September 13, 2004. Although management is unable
to predict the outcome of this case, we recorded a provision in 2003 and the
action is not expected to have a material effect on future results of
operations, financial condition or cash flows. Management cannot predict whether
these governmental agencies will take further action with respect to these
matters.
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 valve, 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 valve in
the Welsh permit, compliance with a fuel sulfur content limit, and compliance
with emission limits for sulfur dioxide.
SWEPCo has previously reported to the TCEQ, deviations related to the receipt of
off-specification fuel at Knox Lee, and the referenced recordkeeping and
reporting requirements and heat input valve 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 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. Management believes the actions are
without merit and intends to vigorously defend 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.
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 E