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 EPA issued a Notice of Violation (NOV) in order to
"perfect" its complaint in the pending litigation. The NOV expands the number of
alleged "modifications" undertaken at the Amos, Cardinal, Conesville, Kammer,
Muskingum River, Sporn and Tanners Creek plants during scheduled outages on
these units from 1979 through the present. Approximately one-third of the
allegations in the NOV are already contained in allegations made by the states
or the special interest groups in the pending litigation. The Federal EPA is
expected to file a motion to amend its complaint, and, to the extent that motion
seeks to expand the scope of the pending litigation, the AEP subsidiaries will
oppose that motion.
We are unable to estimate the loss or range of loss related to any contingent
liability we might have for civil penalties under the CAA proceedings. We are
also unable to predict the timing of resolution of these matters due to the
number of alleged violations and the significant number of issues yet to be
determined by the Court. If we do not prevail, any capital and operating costs
of additional pollution control equipment that may be required, as well as any
penalties imposed, would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity.
In other pending CAA litigation against unaffiliated utility companies
referenced in the annual report, the petition for certiorari filed with the
Supreme Court in the TVA litigation was denied by the Court on May 3, 2004. In
addition, the United States has filed a notice of appeal with the Fourth Circuit
Court of Appeals from the adverse decision in the Duke case, and a briefing
order has been issued by the Court that will require briefing to be completed by
late September 2004.
Clean Water Act Regulation
- --------------------------
On July 9, 2004, the Federal EPA published in the Federal Register a rule
pursuant to the Clean Water Act that will require all large existing,
once-through cooled power plants to meet certain performance standards to reduce
the mortality of juvenile and adult fish or other larger organisms pinned
against a plant's cooling water intake screens. All plants must reduce fish
mortality by 80% to 95%. A subset of these plants that are located on sensitive
water bodies will be required to meet additional performance standards for
reducing the number of smaller organisms passing through the water screens and
the cooling system. These plants must reduce the rate of smaller organisms
passing through the plant by 60% to 90%. Sensitive water bodies are defined as
oceans, estuaries, the Great Lakes, and small rivers with large plants. These
rules will result in additional capital and operation and maintenance expenses
to ensure compliance. The estimated capital cost of compliance for our
facilities, based on the Federal EPA's analysis in the rule, is $193 million.
Any capital costs associated with compliance activities to meet the new
performance standards would likely be incurred during the years 2008 through
2010. We have not independently confirmed the accuracy of the Federal EPA's
estimate. The rule has provisions to limit compliance costs. We may propose less
costly site-specific performance criteria if our compliance cost estimates are
significantly greater than the Federal EPA's estimates or greater than the
environmental benefits. The rule also allows us to propose mitigation (also
called restoration measures) that is less costly and has equivalent or superior
environmental benefits than meeting the criteria in whole or in part. Several
states, electric utilities (including our APCo subsidiary) and environmental
groups appealed certain aspects of the rule. We cannot predict the outcome of
the appeals.
Spent Nuclear Fuel Disposal
- ---------------------------
As a result of DOE's failure to make sufficient progress toward a permanent
repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and
STP Nuclear Operating Company on behalf of TCC and the other STP owners, along
with a number of unaffiliated utilities and states, filed suit in the D.C.
Circuit Court requesting, among other things, that the D.C. Circuit Court order
DOE to meet its obligations under the law. The D.C. Circuit Court ordered the
parties to proceed with contractual remedies but declined to order DOE to begin
accepting SNF for disposal. DOE estimates its planned site for the nuclear waste
will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in
the U.S. Court of Federal Claims seeking damages in excess of $150 million due
to the DOE's partial material breach of its unconditional contractual deadline
to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were
filed by other utilities. In August 2000, in an appeal of related cases
involving other unaffiliated utilities, the U.S. Court of Appeals for the
Federal Circuit held that the delays clause of the standard contract between
utilities and the DOE did not apply to DOE's complete failure to perform its
contract obligations, and that the utilities' suits against DOE may continue in
court. On January 17, 2003, the U.S. Court of Federal Claims ruled in favor of
I&M on the issue of liability. The case continued on the issue of damages owed
to I&M by the DOE. In May 2004, the U.S. Court of Federal Claims ruled against
I&M and denied damages. In July 2004, I&M appealed this ruling to the U.S. Court
of Appeals for the Federal Circuit. As long as the delay in the availability of
a government approved storage repository for SNF continues, the cost of both
temporary and permanent storage of SNF and the cost of decommissioning will
continue to increase. If such cost increases are not recovered on a timely basis
in regulated rates, future results of operations and cash flows could be
adversely affected.
Nuclear Decommissioning
- -----------------------
As discussed in the 2003 Annual Report, decommissioning costs are accrued over
the service life of STP. The licenses to operate the two nuclear units at STP
expire in 2027 and 2028. TCC had estimated its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of approximately $8 million per year.
In May 2004, an updated decommissioning study was completed for STP. The study
estimates TCC's share of the decommissioning costs of STP to be $344 million in
nondiscounted 2004 dollars. TCC is in the process of selling its ownership
interest in STP to a non-affiliate, and upon completion of the sale it is
anticipated that TCC will no longer be obligated for nuclear decommissioning
liabilities associated with STP.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Management's Financial Discussion and
Analysis of Results of Operations" in the 2003 Annual Report for a discussion of
the estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
Other Matters
- -------------
As discussed in our 2003 Annual Report, there are several "Other Matters"
affecting us, including FERC's proposed standard market design and FERC's market
power mitigation efforts. These were no significant changes to the status of
FERC's proposed standard market design. The current status of FERC's market
power mitigation efforts is described below.
FERC Market Power Mitigation
- ----------------------------
A FERC order issued in November 2001 on AEP's triennial market based wholesale
power rate authorization update required certain mitigation actions that AEP
would need to take for sales/purchases within its control area and required AEP
to post information on its website regarding its power system's status. As a
result of a request for rehearing filed by AEP and other market participants,
FERC issued an order delaying the effective date of the mitigation plan until
after a planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. In April 2004, the FERC issued two orders concerning
utilities' ability to sell wholesale electricity at market based rates. In the
first order, the FERC adopted two new interim screens for assessing potential
generation market power of applicants for wholesale market based rates, and
described additional analyses and mitigation measures that could be presented if
an applicant does not pass one of these interim screens. In July 2004, the FERC
issued an order on rehearing affirming its conclusions in the April order and
directing AEP and two unaffiliated utilities to file generation market power
analyses within 30 days. In the second order, the FERC initiated a rulemaking to
consider whether the FERC's current methodology for determining whether a public
utility should be allowed to sell wholesale electricity at market-based rates
should be modified in any way. We plan to present evidence to demonstrate that
we do not possess market power in geographic areas where we sell wholesale
power.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
As a major power producer and marketer of wholesale electricity and natural gas,
we have certain market risks inherent in our business activities. These risks
include commodity price risk, interest rate risk, foreign exchange risk and
credit risk. They represent the risk of loss that may impact us due to changes
in the underlying market prices or rates.
We have established policies and procedures that allow us to identify, assess,
and manage market risk exposures in our day-to-day operations. Our risk policies
have been reviewed with our Board of Directors and approved by our Risk
Executive Committee. Our Chief Risk Officer administers our risk policies and
procedures. The Risk Executive Committee establishes risk limits, approves risk
policies, and assigns responsibilities regarding the oversight and management of
risk and monitors risk levels. Members of this committee receive daily, weekly,
and monthly reports regarding compliance with policies, limits and procedures.
Our committee meets monthly and consists of the Chief Risk Officer, Credit Risk
Management, Market Risk Oversight, and senior financial and operating managers.
We actively participate in the Committee of Chief Risk Officers (CCRO) to
develop standard disclosures for risk management activities around risk
management contracts. The CCRO is composed of the chief risk officers of major
electricity and gas companies in the United States. The CCRO adopted disclosure
standards for risk management contracts to improve clarity, understanding and
consistency of information reported. Implementation of the disclosures is
voluntary. We support the work of the CCRO and have embraced the disclosure
standards. The following tables provide information on our risk management
activities.
Mark-to-Market Risk Management Contract Net Assets (Liabilities)
- ----------------------------------------------------------------
This table provides detail on changes in our mark-to-market (MTM) net asset or
liability balance sheet position from one period to the next.
MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 2004
Investments Investments
Utility Gas UK
Operations Operations Operations (i) Consolidated
---------- ----------- -------------- ------------
(in millions)
Total MTM Risk Management Contract Net Assets
(Liabilities) at December 31, 2003 $286 $5 $(246) $45
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (77) - 243 166
Fair Value of New Contracts When Entered
Into During the Period (b) - - - -
Net Option Premiums Paid/(Received) (c) 8 14 1 23
Change in Fair Value Due to Valuation Methodology
Changes (d) 3 - - 3
Changes in Fair Value of Risk Management
Contracts (e) 48 (45) (30) (27)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (f) (1) - - (1)
----- ----- ------ -----
Total MTM Risk Management Contract Net Assets
(Liabilities) at June 30, 2004 $267 $(26) $(32) 209
===== ===== ======
Net Cash Flow Hedge Contracts (g) (31)
Net Risk Management Liabilities
Held for Sale, included in the totals above (h) 18
-----
Ending Net Risk Management Assets at June 30, 2004 $196
=====
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 and were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value at inception of long-term
contracts entered into with customers during 2004. Most of the fair
value comes from longer term fixed price contracts with customers
that seek to limit their risk against fluctuating energy prices. The
contract prices are valued against market curves associated with the
delivery location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
storage, etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Operations. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed in detail
within the following pages.
(h) See Note 7 for discussion of Assets Held for Sale.
(i) During 2004, we began to unwind our risk management contracts
within the U.K. as part of our planned divestiture of our UK Operations.
We completed the sale of substantially all of our operations and
assets in the Investments-UK Operations segment in July 2004.
Detail on MTM Risk Management Contract Net Assets (Liabilities)
As of June 30, 2004
Investments Investments
Utility Gas UK
Operations Operations Operations Consolidated
---------- ----------- ----------- ------------
(in millions)
Current Assets $560 $229 $194 $983
Non Current Assets 368 153 56 577
------ ------ ------ --------
Total Assets $928 $382 $250 $1,560
------ ------ ------ --------
Current Liabilities $(451) $(239) $(233) $(923)
Non Current Liabilities (210) (169) (49) (428)
------ ------ ------ --------
Total Liabilities $(661) $(408) $(282) $(1,351)
------ ------ ------ --------
Total Net Assets (Liabilities),
excluding Cash Flow Hedges $267 $(26) $(32) $209
====== ====== ====== ========
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of June 30, 2004
Risk
Management Cash Flow Assets Held
Contracts* Hedges for Sale Consolidated
---------- --------- ----------- ------------
(in millions)
Current Assets $983 $82 $(251) $814
Non Current Assets 577 6 (56) 527
-------- ------ ------ --------
Total Assets $1,560 $88 $(307) $1,341
-------- ------ ------ --------
Current Liabilities $(923) $(105) $276 $(752)
Non Current Liabilities (428) (14) 49 (393)
-------- ------ ------ --------
Total Liabilities $(1,351) $(119) $325 $(1,145)
-------- ------ ------ --------
Total Net Assets (Liabilities) $209 $(31) $18 $196
======== ====== ====== ========
*Excluding Cash Flow Hedges.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
(Liabilities)
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets (liabilities) provides two fundamental pieces of
information.
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities)
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in millions)
Utility Operations:
Prices Actively Quoted - Exchange
Traded Contracts $(28) $(32) $1 $4 $- $- $(55)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 88 44 12 7 3 - 154
Prices Based on Models and Other
Valuation Methods (b) 7 55 14 27 20 45 168
----- ----- ----- ---- ---- ---- -----
Total $67 $67 $27 $38 $23 $45 $267
----- ----- ----- ---- ---- ---- -----
Investments - Gas Operations:
Prices Actively Quoted - Exchange
Traded Contracts $36 $42 $(2) $1 $- $- $77
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (51) 14 - - - - (37)
Prices Based on Models and Other
Valuation Methods (b) 1 (48) (8) (3) (3) (5) (66)
----- ----- ----- ---- ---- ---- -----
Total $(14) $8 $(10) $(2) $(3) $(5) $(26)
----- ----- ----- ---- ---- ---- -----
Investments - UK Operations:
Prices Actively Quoted - Exchange
Traded Contracts $- $- $- $- $- $- $-
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (4) (31) 6 - - - (29)
Prices Based on Models and Other
Valuation Methods (b) (3) - - - - - (3)
----- ----- ----- ---- ---- ---- -----
Total $(7) $(31) $6 $- $- $- $(32)
----- ----- ----- ---- ---- ---- -----
Consolidated:
Prices Actively Quoted - Exchange
Traded Contracts $8 $10 $(1) $5 $- $- $22
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 33 27 18 7 3 - 88
Prices Based on Models and Other
Valuation Methods (b) 5 7 6 24 17 40 99
----- ----- ----- ---- ---- ---- -----
Total $46 $44 $23 $36 $20 $40 $209
===== ===== ===== ==== ==== ==== =====
(a) Prices provided by other external sources - Reflects information obtained
from over-the-counter brokers, industry services, or multiple-party
on-line platforms.
(b) Modeled - In the absence of pricing information from external sources,
modeled information is derived using valuation models developed by the
reporting entity, reflecting when appropriate, option pricing theory,
discounted cash flow concepts, valuation adjustments, etc. and may
require projection of prices for underlying commodities beyond the
period that prices are available from third-party sources. In addition,
where external pricing information or market liquidity are limited,
such valuations are classified as modeled.
(c) Amounts exclude Cash Flow Hedges.
The determination of the point at which a market is no longer liquid for placing
it in the Modeled category in the preceding table varies by market. The
following table reports an estimate of the maximum tenors (contract maturities)
of the liquid portion of each energy market.
Maximum Tenor of the Liquid Portion of Risk Management Contracts
As of June 30, 2004
Domestic Transaction Class Market/Region Tenor
-------- ----------------- ------------- -----
(in months)
Natural Gas Futures NYMEX Henry Hub 66
Physical Forwards Gulf Coast, Texas 18
Swaps Gas East - Northeast, Mid-continent
Gulf Coast, Texas 18
Swaps Gas West - Rocky Mountains,
West Coast 18
Exchange Option Volatility NYMEX/Henry Hub 12
Power Futures PJM 30
Physical Forwards Cinergy 42
Physical Forwards PJM 42
Physical Forwards NYPP 30
Physical Forwards NEPOOL 18
Physical Forwards ERCOT 18
Physical Forwards TVA -
Physical Forwards Com Ed 18
Physical Forwards Entergy 8
Physical Forwards PV, NP15, SP15, MidC, Mead 54
Peak Power Volatility (Options) Cinergy 12
Peak Power Volatility (Options) PJM 12
Crude Oil Swaps West Texas Intermediate 30
Emissions Credits SO2 30
Coal Physical Forwards PRB, NYMEX, CSX 30
International
-------------
Power Forwards and Options United Kingdom 24
Coal Forward Purchases and Sales United Kingdom 15
Swaps Europe 36
Freight Swaps Europe 24
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. International subsidiaries use currency swaps to hedge exchange rate
fluctuations of debt denominated in foreign currencies. We do not hedge all
foreign currency exposure.
The tables below provide detail on effective cash flow hedges under SFAS 133
included in our balance sheet. The data in the first table will indicate the
magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts
designated as cash flow hedges are recorded in AOCI, therefore, economic hedge
contracts which are not designated as cash flow hedges are required to be
marked-to-market and are included in the previous risk management tables. This
table further indicates what portions of these hedges are expected to be
reclassified into net income in the next 12 months. The second table provides
the nature of changes from December 31, 2003 to June 30, 2004.
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities. In accordance with accounting
principles generally accepted in the United States of America, all amounts are
presented net of related income taxes.
Cash Flow Hedges included in Accumulated Other Comprehensive Loss
On the Balance Sheet as of June 30, 2004
Portion Expected to
Accumulated Other be Reclassified to
Comprehensive Earnings During the
Loss After Tax (a) Next 12 Months (b)
-------------------- -------------------
(in millions)
Power, Gas and Coal $(4) $-
Foreign Currency (10) (9)
Interest Rate (5) (3)
----- -----
Total $(19) $(12)
===== =====
Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2004
Power, Gas Foreign
and Coal Currency Interest Rate Consolidated
---------- -------- ------------- ------------
(in millions)
Beginning Balance,
December 31, 2003 $(65) $(20) $(9) $(94)
Changes in Fair Value (c) 5 (4) - 1
Reclassifications from AOCI to Net
Income (d) 56 14 4 74
----- ----- ---- -----
Ending Balance,
June 30, 2004 $(4) $(10) $(5) $(19)
===== ===== ==== =====
(a) "Accumulated Other Comprehensive Income (Loss) After Tax" -
Gains/losses are net of related income taxes that have not yet been
included in the determination of net income; reported as a separate
component of shareholders' equity on the balance sheet.
(b) "Portion Expected to be Reclassified to Earnings During the Next 12
Months" - Amount of gains or losses (realized or unrealized) from
derivatives used as hedging instruments that have been deferred and
are expected to be reclassified into net income during the next 12
months at the time the hedged transaction affects net income.
(c) "Changes in Fair Value" - Changes in the fair value of derivatives
designated as cash flow hedges not yet reclassified into net income,
pending the hedged items affecting net income. Amounts are reported
net of related income taxes.
(d) "Reclassifications from AOCI to Net Income" - Gains or losses from
derivatives used as hedging instruments in cash flow hedges that were
reclassified into net income during the reporting period. Amounts are
reported net of related income taxes above.
Credit Risk
- -----------
We limit credit risk by assessing creditworthiness of potential counterparties
before entering into transactions with them and continue to evaluate their
creditworthiness after transactions have been initiated. Only after an entity
has met our internal credit rating criteria will we extend unsecured credit. We
use Moody's Investor Service, Standard and Poor's and qualitative and
quantitative data to assess independently the financial health of counterparties
on an ongoing basis. Our independent analysis, in conjunction with the rating
agencies' information, is used to determine appropriate risk parameters. We also
require cash deposits, letters of credit and parental/affiliate guarantees as
security from counterparties depending upon credit quality in our normal course
of business.
We have risk management contracts with numerous counterparties. Since open risk
management contracts are valued based on changes in market prices of the related
commodities, our exposures change daily. Except for one counterparty who has a
net exposure of approximately $44 million, we believe that credit exposure with
any one counterparty is not material to our financial condition at June 30,
2004. At June 30, 2004, our credit exposure net of credit collateral to sub
investment grade counterparties was approximately 21% expressed in terms of net
MTM assets and net receivables. The concentration in non-investment grade credit
quality was largely due to coal exposures related to financially weak domestic
coal counterparties and coal and freight exposures related to our U.K.
investments. These exposures were driven by the continued high levels of prices
for coal and freight. As of June 30, 2004, the following table approximates our
counterparty credit quality and exposure based on netting across commodities and
instruments:
Number of Net Exposure of
Counterparty Exposure Before Credit Net Counterparties Counterparties
Credit Quality Credit Collateral Collateral Exposure > 10% > 10%
- -------------- ----------------- ---------- -------- -------------- ---------------
(in millions, except number of counterparties)
Investment Grade $877 $138 $739 1 $75
Split Rating 24 2 22 2 20
Non-Investment Grade 325 171 154 3 94
No External Ratings:
Internal Investment
Grade 345 9 336 1 58
Internal Non-Investment
Grade 176 41 135 2 43
------- ----- ------- - -----
Total $1,747 $361 $1,386 9 $290
======= ===== ======= = =====
Generation Plant Hedging Information
- ------------------------------------
This table provides information on operating measures regarding the proportion
of output of our generation facilities (based on economic availability
projections) economically hedged, including both contracts designated as cash
flow hedges under SFAS 133 and contracts not designated as cash flow hedges.
This information is forward-looking and provided on a prospective basis through
December 31, 2006. Please note that this table is a point-in-time estimate,
subject to changes in market conditions and our decisions on how to manage
operations and risk. "Estimated Plant Output Hedged," represents the portion of
megawatthours of future generation/production for which we have sales
commitments or estimated requirement obligations to customers.
Generation Plant Hedging Information
Estimated Next Three Years
As of June 30, 2004
Remainder
2004 2005 2006
---- ---- ----
Estimated Plant Output Hedged 90% 89% 87%
VaR Associated with Risk Management Contracts
- ---------------------------------------------
We use a risk measurement model, which calculates Value at Risk (VaR) to measure
our commodity price risk in the risk management portfolio. The VaR is based on
the variance-covariance method using historical prices to estimate volatilities
and correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at June 30, 2004, a near term typical change
in commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The following table shows the end, high, average, and low market risk as
measured by VaR year-to-date:
VaR Model
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
----------------------- -----------------------
(in millions) (in millions)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$3 $19 $7 $2 $11 $19 $7 $4
The 2004 High VaR was due to the wind-down of the London risk management
activities. These activities were concluded in March 2004. The 2004 High VaR,
excluding London activities, was approximately $8 million.
Our VaR model results are adjusted using standard statistical treatments to
calculate the CCRO VaR reporting metrics listed below.
CCRO VaR Metrics
Average for
Year-to-Date High for Low for
June 30, 2004 2004 Year-to-Date 2004 Year-to-Date 2004
------------- ------------ ------------------ -----------------
(in millions)
95% Confidence Level, Ten-Day
Holding Period $13 $26 $73 $7
99% Confidence Level, One-Day
Holding Period $5 $11 $30 $3
We utilize a VaR model to measure interest rate market risk exposure. The
interest rate VaR model is based on a Monte Carlo simulation with a 95%
confidence level and a one-year holding period. The volatilities and
correlations were based on three years of daily prices. The risk of potential
loss in fair value attributable to our exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $903 million at June
30, 2004 and $1.013 billion at December 31, 2003. We would not expect to
liquidate our entire debt portfolio in a one-year holding period, therefore a
near term change in interest rates should not materially affect our results of
operations, cash flows or consolidated financial position.
We are exposed to risk from changes in the market prices of coal and natural gas
used to generate electricity where generation is no longer regulated or where
existing fuel clauses are suspended or frozen. The protection afforded by fuel
clause recovery mechanisms has either been eliminated by the implementation of
customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of
Texas (effective January 1, 2002) or frozen by a settlement agreement in West
Virginia. To the extent the fuel supply of the generating units in these states
is not under fixed-price long-term contracts, we are subject to market price
risk. We continue to be protected against market price changes by active fuel
clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of
Texas. Fuel clauses are active again in Michigan and Indiana, effective January
1, 2004 and March 1, 2004, respectively.
We employ risk management contracts including physical forward purchase and sale
contracts, exchange futures and options, over-the-counter options, swaps, and
other derivative contracts to offset price risk where appropriate. We engage in
risk management of electricity, gas and to a lesser degree other commodities,
principally coal and freight. As a result, we are subject to price risk. The
amount of risk taken is controlled by risk management operations and our Chief
Risk Officer and his staff. When risk management activities exceed certain
pre-determined limits, the positions are modified or hedged to reduce the risk
to be within the limits unless specifically approved by the Risk Executive
Committee.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2004 and 2003
(in millions, except per-share amounts)
(Unaudited)
Three Months Ended Six Months Ended
------------------------ --------------------
2004 2003 2004 2003
---- ---- ---- ----
REVENUES
- ------------------------------------------------------
Utility Operations $2,501 $2,672 $5,080 $5,359
Gas Operations 777 638 1,429 1,571
Other 90 140 200 305
------- ------- ------- -------
TOTAL 3,368 3,450 6,709 7,235
------- ------- ------- -------
EXPENSES
- ------------------------------------------------------
Fuel for Electric Generation 734 759 1,428 1,492
Purchased Electricity for Resale 87 214 170 370
Purchased Gas for Resale 701 650 1,286 1,528
Maintenance and Other Operation 972 946 1,836 1,835
Depreciation and Amortization 320 331 639 642
Taxes Other Than Income Taxes 176 157 360 345
------- ------- ------- -------
TOTAL 2,990 3,057 5,719 6,212
------- ------- ------- -------
OPERATING INCOME 378 393 990 1,023
------- ------- ------- -------
Other Income (Expense), Net 51 50 91 116
------- ------- ------- -------
INTEREST AND OTHER CAPITAL CHARGES
- ------------------------------------------------------
Interest 199 197 398 389
Preferred Stock Dividend Requirements of Subsidiaries 1 3 3 6
Minority Interest in Finance Subsidiary - 8 - 17
------- ------- ------- -------
TOTAL 200 208 401 412
------- ------- ------- -------
INCOME BEFORE INCOME TAXES 229 235 680 727
Income Taxes 78 58 240 257
------- ------- ------- -------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGES 151 177 440 470
DISCONTINUED OPERATIONS (Net of Tax) (51) (2) (58) (48)
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (Net of Tax)
- ------------------------------------------------------
Accounting for Risk Management Contracts - - - (49)
Asset Retirement Obligations - - - 242
------- ------- ------- -------
NET INCOME $100 $175 $382 $615
======= ======= ======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 396 395 396 376
======= ======= ======= =======
EARNINGS PER SHARE
- ------------------------------------------------------
Income Before Discontinued Operations and Cumulative
Effect of Accounting Changes $0.38 $0.45 $1.11 $1.25
Discontinued Operations (0.13) (0.01) (0.15) (0.12)
Cumulative Effect of Accounting Changes - - - 0.51
------- ------- ------- -------
TOTAL EARNINGS PER SHARE (BASIC AND DILUTED) $0.25 $0.44 $0.96 $1.64
======= ======= ======= =======
CASH DIVIDENDS PAID PER SHARE $0.35 $0.35 $0.70 $0.95
======= ======= ======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in millions)
CURRENT ASSETS
- ----------------------------------------------------
Cash and Cash Equivalents $858 $976
Other Cash Deposits 208 206
Accounts Receivable:
Customers 1,044 1,155
Accrued Unbilled Revenues 560 596
Miscellaneous 75 83
Allowance for Uncollectible Accounts (133) (124)
-------- --------
Total Receivables 1,546 1,710
-------- --------
Fuel, Materials and Supplies 1,192 991
Risk Management Assets 814 766
Margin Deposits 128 119
Other 119 129
-------- --------
TOTAL 4,865 4,897
-------- --------
PROPERTY, PLANT AND EQUIPMENT
- ----------------------------------------------------
Electric:
Production 15,663 15,112
Transmission 6,223 6,130
Distribution 10,078 9,902
Other (including gas, coal mining and nuclear fuel) 3,613 3,572
Construction Work in Progress 967 1,305
-------- --------
TOTAL 36,544 36,021
Less: Accumulated Depreciation and Amortization 14,363 14,004
-------- --------
TOTAL-NET 22,181 22,017
-------- --------
OTHER NON-CURRENT ASSETS
- ----------------------------------------------------
Regulatory Assets 3,521 3,548
Securitized Transition Assets 670 689
Spent Nuclear Fuel and Decommissioning Trusts 1,013 982
Investments in Power and Distribution Projects 214 212
Goodwill 78 78
Long-term Risk Management Assets 527 494
Other 724 733
-------- --------
TOTAL 6,747 6,736
-------- --------
Assets Held for Sale 2,055 2,761
Assets of Discontinued Operations - 333
TOTAL ASSETS $35,848 $36,744
======== ========
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in millions)
CURRENT LIABILITIES
- ---------------------------------------------------------------------------------
Accounts Payable $1,165 $1,337
Short-term Debt 596 326
Long-term Debt Due Within One Year* 1,865 1,779
Risk Management Liabilities 752 631
Accrued Taxes 762 620
Accrued Interest 199 207
Customer Deposits 462 379
Other 627 703
-------- --------
TOTAL 6,428 5,982
-------- --------
NON-CURRENT LIABILITIES
- ---------------------------------------------------------------------------------
Long-term Debt* 11,533 12,322
Long-term Risk Management Liabilities 393 335
Deferred Income Taxes 4,144 3,957
Regulatory Liabilities and Deferred Investment Tax Credits 2,277 2,259
Asset Retirement Obligations and Nuclear Decommissioning 693 651
Employee Benefits and Pension Obligations 676 667
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 171 176
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption 72 76
Deferred Credits and Other 542 508
-------- --------
TOTAL 20,501 20,951
-------- --------
Liabilities Held for Sale 775 1,710
Liabilities of Discontinued Operations - 166
TOTAL LIABILITIES 27,704 28,809
-------- --------
Cumulative Preferred Stocks of Subsidiaries not Subject to Mandatory Redemption 61 61
Commitments and Contingencies
COMMON SHAREHOLDERS' EQUITY
- ---------------------------------------------------------------------------------
Common Stock-Par Value $6.50:
2004 2003
---- ----
Shares Authorized. . . . . . . . . . .600,000,000 600,000,000
Shares Issued. . . . . . . . . . . . .404,657,511 404,016,413
(8,999,992 shares were held in treasury at June 30, 2004 and December 31, 2003) 2,630 2,626
Paid-in Capital 4,193 4,184
Retained Earnings 1,595 1,490
Accumulated Other Comprehensive Income (Loss) (335) (426)
-------- --------
TOTAL 8,083 7,874
-------- --------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $35,848 $36,744
======== ========
* See Accompanying Schedule
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in millions)
OPERATING ACTIVITIES
- ------------------------------------------------------
Net Income $382 $615
Plus: Discontinued Operations 58 48
------ -------
Income from Continuing Operations 440 663
Adjustments for Noncash Items:
Depreciation and Amortization 639 642
Deferred Income Taxes 92 42
Deferred Investment Tax Credits (13) (16)
Cumulative Effect of Accounting Changes - (193)
Amortization of Deferred Property Taxes (2) -
Amortization of Cook Plant Restart Costs - 20
Mark-to-Market of Risk Management Contracts 50 (33)
Over/Under Fuel Recovery (4) 85
Change in Other Non-Current Assets 38 (94)
Change in Other Non-Current Liabilities 90 (13)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net 167 (9)
Accounts Payable (180) (136)
Fuel, Materials and Supplies (196) (40)
Customer Deposits and Risk Management Collateral 83 167
Taxes Accrued 140 62
Interest Accrued (8) (16)
Other Current Assets (1) (60)
Other Current Liabilities (73) (221)
------ -------
Net Cash Flows From Operating Activities 1,262 850
------ -------
INVESTING ACTIVITIES
- ------------------------------------------------------
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)
------ -------
FINANCING ACTIVITIES
- ------------------------------------------------------
Issuance of Common Stock 11 1,142
Issuance of Long-term Debt 263 3,472
Change in Short-term Debt, Net 188 (2,218)
Retirement of Long-term Debt (986) (1,407)
Retirement of Preferred Stock (4) (2)
Retirement of Minority Interest - (225)
Dividends Paid on Common Stock (277) (342)
------ -------
Net Cash Flows From (Used For) Financing Activities (805) 420
------ -------
Net Decrease in Cash and Cash Equivalents (118) (18)
Cash and Cash Equivalents at Beginning of Period 976 1,088
------ -------
Cash and Cash Equivalents at End of Period $858 $1,070
====== =======
Net Increase in Cash and Cash Equivalents from Discontinued Operations $2 $15
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 13 23
------ -------
Cash and Cash Equivalents from Discontinued Operations - End of Period $15 $38
====== =======
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest, net of capitalized amounts, was $378 million and $366 million in 2004 and 2003, respectively. Cash paid
(received) for income taxes was $(43) million and $155 million in 2004 and 2003, respectively. Noncash acquisitions under capital
leases were $27 million and $0 in 2004 and 2003, respectively.
In connection with the disposition of AEP Coal in April 2004 the buyer assumed $11 million of non-current liabilities.
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND
COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in millions)
(Unaudited)
Accumulated
Common Stock Other
----------------- Paid-in Retained Comprehensive
Shares Amount Capital Earnings Income (Loss) Total
------ ------ ------- -------- ------------- -----
DECEMBER 31, 2002 348 $2,261 $3,413 $1,999 $(609) $7,064
Issuance of Common Stock 56 365 812 1,177
Common Stock Dividends (342) (342)
Common Stock Expense (35) (35)
Other (8) 3 (5)
-------
TOTAL 7,859
-------
COMPREHENSIVE INCOME
- -------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments 23 23
Cash Flow Hedges (100) (100)
Securities Available for Sale 1 1
Minimum Pension Liability 15 15
NET INCOME 615 615
-------
TOTAL COMPREHENSIVE INCOME 554
---- ------- ------- ------- ------ -------
JUNE 30, 2003 404 $2,626 $4,182 $2,275 $(670) $8,413
==== ======= ======= ======= ====== =======
DECEMBER 31, 2003 404 $2,626 $4,184 $1,490 $(426) $7,874
Issuance of Common Stock 1 4 7 11
Common Stock Dividends (277) (277)
Other 2 2
-------
TOTAL 7,610
-------
COMPREHENSIVE INCOME
- -------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments (1) (1)
Cash Flow Hedges 75 75
Minimum Pension Liability 17 17
NET INCOME 382 382
-------
TOTAL COMPREHENSIVE INCOME 473
---- ------- ------- ------- ------ -------
JUNE 30, 2004 405 $2,630 $4,193 $1,595 $(335) $8,083
==== ======= ======= ======= ====== =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in millions)
TOTAL LONG-TERM DEBT OUTSTANDING
--------------------------------
First Mortgage Bonds $556 $822
Defeased TCC First Mortgage Bonds (a) 112 118
Installment Purchase Contracts 1,936 2,026
Notes Payable 1,409 1,518
Senior Unsecured Notes 7,840 7,997
Securitization Bonds 718 746
Notes Payable to Trust 254 331
Equity Unit Senior Notes 345 345
Long-term DOE Obligation (b) 227 226
Other Long-term Debt 41 21
Equity Unit Contract Adjustment Payments 14 19
Unamortized Discount (net) (54) (68)
-------- --------
TOTAL 13,398 14,101
Less Portion Due Within One Year 1,865 1,779
-------- --------
TOTAL LONG-TERM PORTION $11,533 $12,322
======== ========
(a) On May 7, 2004, we deposited cash and treasury securities of $124.5
million with a trustee to defease all of TCC's outstanding First Mortgage
Bonds. Trust fund assets related to this obligation of $103 million are
included in Other Cash Deposits and $22 million in Other Non-current Assets
in the Consolidated Balance Sheets at June 30, 2004. Trust fund assets are
restricted for exclusive use in retiring the First Mortgage Bonds.
(b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear
licensee) has an obligation with the United States Department of Energy for
spent nuclear fuel disposal. The obligation includes a one-time fee for
nuclear fuel consumed prior to April 7, 1983. I&M is the only AEP subsidiary
that generated electric power with nuclear fuel prior to that date. Trust
fund assets of $259 million and $262 million related to this obligation are
included in Spent Nuclear Fuel and Decommissioning Trusts in the
Consolidated Balance Sheets at June 30, 2004 and December 31, 2003,
respectively.
AMERICAN ELECTRIC POWER, INC. AND SUBSIDIARY COMPANIES
INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------------------
1. Significant Accounting Matters
2. New Accounting Pronouncements
3. Rate Matters
4. Customer Choice and Industry Restructuring
5. Commitments and Contingencies
6. Guarantees
7. Dispositions, Discontinued Operations and Assets Held for Sale
8. Benefit Plans
9. Business Segments
10. Financing Activities
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
--------------------------------------------------------------
1. SIGNIFICANT ACCOUNTING MATTERS
------------------------------
General
- -------
The accompanying unaudited interim financial statements should be read in
conjunction with the 2003 Annual Report as incorporated in and filed with our
2003 Form 10-K.
In the opinion of management, the unaudited interim financial statements reflect
all normal and recurring accruals and adjustments which are necessary for a fair
presentation of the results of operations for interim periods.
Other Income (Expense), Net
- ---------------------------
The following table provides the components of Other Income (Expense), Net as
presented on our Consolidated Statements of Operations:
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Other Income:
- -------------
Interest and Dividend Income $5 $8 $11 $13
Equity Earnings 3 1 10 2
Nonoperating Revenue 28 38 57 66
Gain on Sale of REPs (Mutual Energy Companies) - - - 39
Other 56 52 85 89
---- ---- ---- -----
Total Other Income 92 99 163 209
---- ---- ---- -----
Other Expense:
- --------------
Nonoperating Expenses 22 34 46 60
Other 19 15 26 33
---- ---- ---- -----
Total Other Expense 41 49 72 93
---- ---- ---- -----
Total Other Income (Expense), Net $51 $50 $91 $116
==== ==== ==== =====
Components of Accumulated Other Comprehensive Income (Loss)
- -----------------------------------------------------------
The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income
(Loss):
Components June 30, December 31,
- ---------- 2004 2003
---- ----
(in millions)
Foreign Currency Translation Adjustments $109 $110
Unrealized Losses on Securities Available for Sale (1) (1)
Unrealized Losses on Cash Flow Hedges (19) (94)
Minimum Pension Liability (424) (441)
------ ------
Total $(335) $(426)
====== ======
At June 30, 2004, we expect to reclassify approximately $12 million of net
losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to
Net Income during the next twelve months at the time the hedged transactions
affect net income. Two years is the maximum period over which an exposure to a
variability in future commodity or foreign currency related cash flows is hedged
with SFAS 133 designated contracts. Approximately $1 million of the fair value
of cash flow hedges at June 30, 2004 are hedging interest rate variability on
debt past two years. The actual amounts that we reclassify from Accumulated
Other Comprehensive Income (Loss) to Net Income can differ due to market price
changes.
In addition, during the first quarter 2004, we reclassified $23 million from
Accumulated Other Comprehensive Income (Loss) related to minimum pension
liability to regulatory assets ($35 million) and deferred income taxes ($12
million) as a result of authoritative letters issued by the FERC and the
Arkansas and Louisiana commissions.
Accounting for Asset Retirement Obligations
- -------------------------------------------
The following is a reconciliation of the beginning and ending aggregate carrying
amount of asset retirement obligations:
U.K. Plants,
Wind Mills
Nuclear Ash and Mining
Decommissioning Ponds Operations Total
--------------- ----- ------------ -----
(in millions)
Asset Retirement Obligation Liability
at January 1, 2004 Including Held
for Sale $770.9 $75.4 $53.1 $899.4
Accretion Expense 27.7 3.0 1.5 32.2
Foreign Currency
Translation - - 0.3 0.3
Liabilities Incurred - - 17.7 17.7
Liabilities Settled - - (11.3) (11.3)
Revisions in Cash Flow Estimates - - 15.0 15.0
------- ------ ------ -------
Asset Retirement Obligation Liability
at June 30, 2004 including Held
for Sale 798.6 78.4 76.3 953.3
Less Asset Retirement Obligation
Liability Held for Sale:
South Texas Project (a) (227.0) - - (227.0)
U.K. Plants (b) - - (44.8) (44.8)
------- ------ ------ -------
Asset Retirement Obligation
Liability at June 30, 2004 $571.6 $78.4 $31.5 $681.5
======= ====== ====== =======
(a) We have signed an agreement to sell TCC's share of South Texas Project (see Note 7 for additional information).
(b) We closed on the sale of our U.K. plants in late July 2004 (see Note 7 for additional information).
Accretion expense is included in Maintenance and Other Operation expense in our
accompanying Consolidated Statements of Operations.
As of June 30, 2004 and December 31, 2003, the fair value of assets that are
legally restricted for purposes of settling the nuclear decommissioning
liabilities totaled $885 million and $845 million, respectively, of which $754
million and $720 million relating to the Cook Plant was recorded in Spent
Nuclear Fuel and Decommissioning Trusts in our Consolidated Balance Sheets. The
fair value of assets that are legally restricted for purposes of settling the
nuclear decommissioning liabilities for the South Texas Project totaling $131
million and $125 million as of June 30, 2004 and December 31, 2003,
respectively, was classified as Assets Held for Sale in our Consolidated Balance
Sheets.
Reclassifications
- -----------------
Certain prior period financial statement items have been reclassified to conform
to current period presentation. Such reclassifications had no impact on
previously reported Net Income.
2. NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------
FIN 46 (revised December 2003) "Consolidation of Variable Interest Entities"
(FIN 46R)
- ----------------------------------------------------------------------------
We implemented FIN 46R, "Consolidation of Variable Interest Entities," effective
March 31, 2004 with no material impact to our financial statements. FIN 46R is a
revision to FIN 46 which interprets the application of Accounting Research
Bulletin No. 51, "Consolidated Financial Statements," to certain entities in
which equity investors do not have the characteristics of a controlling
financial interest or do not have sufficient equity at risk for the entity to
finance its activities without additional subordinated financial support from
other parties.
FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug Improvement and Modernization Act of
2003
- -------------------------------------------------------------------------------
We implemented FASB Staff Position (FSP) FAS 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003," effective April 1, 2004, retroactive to January 1,
2004. The new disclosure standard provides authoritative guidance on the
accounting for any effects of the Medicare prescription drug subsidy under the
Act. It replaces the earlier FSP FAS 106-1, under which we previously elected to
defer accounting for any effects of the Act until the FASB issued authoritative
guidance on the accounting for the Medicare subsidy.
Under FSP FAS 106-2, the current portion of the Medicare subsidy for employers
who qualify for the tax-free subsidy is a reduction of ongoing FAS 106 cost,
while the retroactive portion is an actuarial gain to be amortized over the
average remaining service period of active employees, to the extent that the
gain exceeds FAS 106's 10 percent corridor. The Medicare subsidy reduced our FAS
106 accumulated postretirement benefit obligation (APBO) related to benefits
attributed to past service by $202 million. The tax-free subsidy reduced the
second quarter's net periodic postretirement benefit cost by a total of $7
million, including $3 million of amortization of the actuarial gain, $1 million
of reduced service cost, and $3 million of reduced interest cost on the APBO.
After adjustment to capitalization of employee benefits costs as a cost of
construction projects, $5 million of this tax-free cost reduction remained to
increase the second quarter's net income.
The effect of implementing FSP FAS 106-2 on the first quarter of 2004 is as
follow:
Three Months Ended March 31, 2004 Earnings in Millions Earnings Per Share
- --------------------------------- -------------------- ------------------
Originally Reported $278 $0.70
Effect of Medicare Subsidy 5 0.02
----- ------
Restated $283 $0.72
===== ======
Future Accounting Changes
- -------------------------
The FASB's standard-setting process is ongoing and until new standards have been
finalized and issued by FASB, we cannot determine the impact on the reporting of
our operations that may result from any such future changes. The FASB is
currently working on several projects including discontinued operations,
business combinations, liabilities and equity, revenue recognition, accounting
for equity-based compensation, pension plans, asset retirement obligations,
earnings per share calculations, fair value measurements, and related tax
impacts. We also expect to see more projects as a result of the FASB's desire to
converge International Accounting Standards with those generally accepted in the
United States of America. The ultimate pronouncements resulting from these and
future projects could have an impact on our future results of operations and
financial position.
3. RATE MATTERS
------------
As discussed in our 2003 Annual Report, our subsidiaries are involved in rate
and regulatory proceedings at the FERC and at several state commissions. The
Rate Matters note within our 2003 Annual Report should be read in conjunction
with this report in order to gain a complete understanding of material rate
matters still pending, without significant changes since year-end. The following
sections discuss current activities.
TNC Fuel Reconciliation
- -----------------------
In 2002, TNC filed with the PUCT to reconcile fuel costs, requesting to defer
any unrecovered portion applicable to retail sales within its ERCOT service area
for inclusion in the 2004 true-up proceeding. This reconciliation for the period
from July 2000 through December 2001 will be the final fuel reconciliation for
TNC's ERCOT service territory.
In March 2003, the ALJ in this proceeding filed a Proposal for Decision (PFD)
with a recommendation that TNC's under-recovered retail fuel balance be reduced.
In March 2003, TNC established a reserve of $13 million based on the
recommendations in the PFD. In May 2003, the PUCT reversed the ALJ on certain
matters and remanded TNC's final fuel reconciliation to the ALJ to consider two
issues: (1) the sharing of off-system sales margins from AEP's trading
activities with customers for five years per the PUCT's interpretation of the
Texas AEP/CSW merger settlement and (2) the inclusion of January 2002 fuel
factor revenues and associated costs in the determination of the under-recovery.
The PUCT proposed that the sharing of off-system sales margins for periods
beyond the termination of the fuel factor should be recognized in the final fuel
reconciliation proceeding. This would result in the sharing of margins for an
additional three and one-half years after the end of the Texas ERCOT fuel
factor. While management believes that the Texas merger settlement only provided
for sharing of margins during the period fuel and generation costs were
regulated by the PUCT, an additional provision of $10 million was recorded in
December 2003.
In December 2003, the ALJ issued a PFD in the remand phase of the TNC fuel
reconciliation recommending additional disallowances for the two remand issues.
TNC filed responses to the PFD and the PUCT announced a final ruling in the fuel
reconciliation proceeding in January 2004 accepting the PFD. TNC received a
written order in March 2004 and increased the reserve by $1.5 million. In March
2004, various parties, including TNC, requested a rehearing of the PUCT's
ruling. In May 2004, the PUCT reversed its position on the inclusion of MTM
amounts in the allocation of system sales margins and remanded the case to the
ALJ. As a result, TNC recorded an additional provision of $12 million in the
second quarter of 2004 resulting in an over-recovery balance of $7 million at
June 30, 2004.
On July 2, 2004, the parties to the MTM remand proceeding filed a "Stipulation
of Fact." All parties agreed to the amount of the remanded issue. If the amounts
included in the "Stipulation of Fact" are approved, the over-recovery balance
will be reduced to $4 million. We expect the PUCT to issue its final order in
this proceeding in August 2004.
TCC Fuel Reconciliation
- -----------------------
In 2002, TCC filed its final fuel reconciliation with the PUCT to reconcile fuel
costs to be included in its deferred over-recovery balance in the 2004 true-up
proceeding. This reconciliation covers the period from July 1998 through
December 2001.
Based on the PUCT ruling in the TNC proceeding relating to similar issues, TCC
established a reserve for potential adverse rulings of $81 million during 2003.
On February 3, 2004, the ALJ issued a PFD recommending that the PUCT disallow
$140 million in eligible fuel costs including some new items not considered in
the TNC case, and other items considered but not disallowed in the TNC ruling.
Based on an analysis of the ALJ's recommendations, TCC established an additional
reserve of $13 million during the first quarter of 2004. In May 2004, the PUCT
accepted most of the ALJ's recommendations. The PUCT rejected the ALJ's
recommendation to impute capacity to certain energy-only purchased power
contracts and remanded the issue to the ALJ to determine if any energy-only
purchased power contracts during the reconciliation period include a capacity
component that is not recoverable in fuel revenues. Hearings are scheduled in
October 2004 for the remand issue. As a result of the PUCT's acceptance of the
ALJ's recommendations and the PUCT's remand decision in the TNC case regarding
the inclusion of MTM amounts in the allocation of AEP's net system sales
margins, TCC increased its provision by $47 million in the second quarter of
2004. The over-recovery balance and the provisions total $210 million including
interest at June 30, 2004. At this time, management is unable to predict the
outcome of this proceeding. An adverse ruling from the PUCT, disallowing amounts
in excess of the established reserve, could have a material impact on future
results of operations and cash flows. Additional information regarding the 2004
true-up proceeding for TCC can be found in Note 4 "Customer Choice and Industry
Restructuring."
SWEPCo Texas Fuel Reconciliation
- --------------------------------
In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in the SPP.
This reconciliation covers the period from January 2000 through December 2002.
During the reconciliation period, SWEPCo incurred $435 million of Texas retail
eligible fuel expense. In November 2003, intervenors and the PUCT Staff
recommended fuel cost disallowances of more than $30 million. In December 2003,
SWEPCo agreed to a settlement in principle with all parties in the fuel
reconciliation. The settlement provides for a disallowance in fuel costs of $8
million which was recorded in December 2003. In April 2004 the PUCT approved the
settlement.
TCC Rate Case
- -------------
On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates should not be
reduced. Other municipalities served by TCC passed similar rate review
resolutions. In Texas, municipalities have original jurisdiction over rates of
electric utilities within their municipal limits. Under Texas law, TCC must
provide support for its rates to the municipalities. TCC filed the requested
support for its rates based on a test year ending June 30, 2003 with all of its
municipalities and the PUCT on November 3, 2003. TCC's proposal would decrease
its wholesale transmission rates by $2 million or 2.5% and increase its retail
energy delivery rates by $69 million or 19.2%. In February 2004, eight
intervening parties and the PUCT Staff filed testimony recommending reductions
to TCC's requested $67 million rate increase. The recommendations ranged from a
decrease in existing rates of approximately $100 million to an increase in TCC's
current rates of approximately $27 million. Hearings were held in March 2004. In
May 2004, TCC agreed to a non-unanimous settlement on cost of capital including
capital structure and return on equity with all but two parties in the
proceeding. TCC agreed that the return on equity should be established at
10.125% based upon a capital structure with 40% equity resulting in a weighted
cost of capital of 7.475%. The settlement and other agreed adjustments reduced
TCC's rate request to $41 million. The ALJs that heard the case issued their
recommendations on July 2, 2004, including a recommendation to approve the cost
of capital settlement. The ALJs recommended that an issue related to the
allocation of consolidated tax savings to the transmission and distribution
utility be remanded for additional evidence. On July 15, 2004, the PUCT agreed
to remand this issue to the ALJs. In addition, the PUCT ordered TCC to calculate
its revenue requirements based upon the recommendations of the ALJs. On July 21,
2004, TCC filed its revenue requirements based upon the recommendations of the
ALJs. The ALJs' recommendations reduce TCC's existing rates by a range of $33
million to $43 million depending on the final resolution of the amount of
consolidation tax savings. TCC filed exceptions to the ALJs' recommendations on
July 21, 2004. The PUCT is expected to issue its decision in September 2004.
Management is unable to predict the ultimate effect of this proceeding on TCC's
rates, revenues, results of operations, cash flows and financial condition.
Louisiana Compliance Filing
- ---------------------------
In October 2002, SWEPCo filed with the Louisiana Public Service Commission
(LPSC) detailed financial information typically utilized in a revenue
requirement filing, including a jurisdictional cost of service. This filing was
required by the LPSC as a result of its order approving the merger between AEP
and CSW. The LPSC's merger order also provides that SWEPCo's base rates are
capped at the present level through mid-2005. In April 2004, SWEPCo filed
updated financial information with a test year ending December 31, 2003 as
required by the LPSC. Both filings indicated that SWEPCo's current rates should
not be reduced. If, after review of the updated information, the LPSC disagrees
with our conclusion, it could order SWEPCo to file all documents for a full cost
of service revenue requirement review in order to determine whether SWEPCo's
capped rates should be reduced, which if a rate reduction is ordered, would
adversely impact results of operations and cash flows.
PSO Fuel and Purchased Power
- ----------------------------
In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting
from a reallocation among AEP West companies of purchased power costs for
periods prior to January 1, 2002. In July 2003, PSO filed with the Corporation
Commission of the State of Oklahoma (OCC) seeking to recover these costs over a
period of 18 months. In August 2003, the OCC Staff filed testimony recommending
PSO be granted recovery of $42.4 million over three years. In September 2003,
the OCC expanded the case to include a full review of PSO's 2001 fuel and
purchased power practices. PSO filed its testimony in February 2004. An
intervenor and the OCC Staff filed testimony in April 2004. The intervenor
suggested that $8.8 million related to the 2002 reallocation not be recovered
from customers. The Attorney General of Oklahoma also filed a statement of
position, indicating allocated trading margins between and among AEP operating
companies were inconsistent with the FERC-approved Operating Agreement and
System Integration Agreement and could more than offset the $44 million 2002
reallocation. The intervenor and the OCC Staff also believed trading margins
were allocated incorrectly and that a reallocation by the intervenors of such
margins would reduce PSO's recoverable fuel by approximately $6.8 million for
2000 and $10.7 million for 2001, while under the OCC Staff method, the amount
for 2001 would be $8.8 million. The intervenor and the OCC Staff also recommend
recalculation of fuel for years subsequent to 2001 using the same methods. At a
June 2004 prehearing conference, PSO questioned whether the issues in dispute
were the jurisdiction of the OCC or the FERC because they relate to the
FERC-approved agreements. As a result, the ALJ ordered that the jurisdictional
issue be briefed by the parties. PSO is required to file its brief by September
1, 2004. Subject to decisions by the OCC as to jurisdiction, a hearing date has
been set for January 2005. Management believes that fuel costs have been
prudently incurred consistent with OCC rules, and that the allocation of trading
margins pursuant to the agreements is correct. If the OCC determines, as a
result of the review that a portion of PSO's fuel and purchased power costs
should not be recovered, there will be an adverse effect on PSO's results of
operations, cash flows and possibly financial condition.
RTO Formation/Integration
- -------------------------
With FERC approval, AEP East companies have been deferring costs incurred under
FERC orders to form an RTO (the Alliance RTO) or join an existing RTO (PJM). In
July 2003, the FERC issued an order approving our continued deferral of both our
Alliance formation costs and our PJM integration costs including the deferral of
a carrying charge. The AEP East companies have deferred approximately $33
million of RTO formation and integration costs and related carrying charges
through June 30, 2004. As a result of the subsequent delay in the integration of
AEP's East transmission system into PJM, FERC declined to rule, in its July 2003
order, on our request to transfer the deferrals to regulatory assets, and to
maintain the deferrals until such time as the costs can be recovered from all
users of AEP's East transmission system. The AEP East companies plan to apply
for permission to transfer the deferred formation/integration costs to a
regulatory asset prior to integration with PJM.
In its July 2003 order, FERC indicated that it would review the deferred costs
at the time they are transferred to a regulatory asset account and scheduled for
amortization and recovery in the open access transmission tariff (OATT) to be
charged by PJM. Management believes that the FERC will grant permission for
prudently incurred deferred RTO formation/integration costs to be amortized and
included in the OATT. Whether the amortized costs will be fully recoverable
depends upon the state regulatory commissions' treatment of AEP East companies'
portion of the OATT as these companies file rate cases. Presently, retail base
rates are frozen or capped and cannot be increased for retail customers of
CSPCo, I&M and OPCo.
In August 2004, we intend to file an application with FERC dividing the RTO
formation/integration costs between payments made to PJM and all other costs. We
will subsequently request that the payments made directly to PJM be recovered
from all users of PJM's transmission and that the balance of the deferred costs
be recovered from load-serving entities within the area served by the AEP East
companies' owned transmission (AEP zone). Most of the amount recoverable in the
AEP zone will be paid by the AEP East companies since it will be attributable to
their internal load. The amount to be recovered in the AEP zone is approximately
one-half of the deferred costs. In our August application, we will seek
permission to delay the amortization of the AEP zone deferred amounts until they
are recoverable from users of the transmission system including our retail
customers or, as an alternative, to use a long amortization period that extends
beyond the rate freezes or caps.
The AEP East companies are scheduled to join PJM in October 2004, although there
are pending proceedings in Virginia concerning our integration into PJM.
Therefore, management is unable to predict the timing of when AEP will join PJM
and if upon joining PJM whether FERC will grant a delay of recovery until the
rate caps and freezes end or a long enough amortization period to allow for the
opportunity for recovery in the East retail jurisdictions. If the AEP East
companies do not obtain regulatory approval to join PJM, we are committed to
reimburse PJM for certain project implementation costs (presently estimated at
$24 million for our share of the entire PJM integration project). Management
intends to seek recovery of the project implementation cost reimbursements, if
incurred. If the FERC ultimately decides not to approve a delay or a long
amortization period or the FERC or the state commissions deny recovery, future
results of operations and cash flows could be adversely affected.
In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO prior to July 1, 2004 and thereafter only
with the approval of the Virginia SCC, but required such transfers by January 1,
2005. In January 2004, APCo filed with the Virginia SCC a cost/benefit study
covering the time period through 2014 as required by the Virginia SCC. The study
results show a net benefit of approximately $98 million for APCo over the
11-year study period from AEP's participation in PJM. In July 2004, after
reaching a unanimous agreement with intervenors to settle the RTO issues in
Virginia, the settlement agreement was submitted to the Virginia SCC. The
settlement provides for approval of APCo's application to join PJM in exchange
for a small annual revenue credit to customers through 2010, or the effective
date of rates established in a new base rate case, some service curtailment
provisions and annual reporting requirements.
In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack
of evidence that it would benefit Kentucky retail customers. In August 2003,
KPCo sought and was granted a rehearing to submit additional evidence. In
December 2003, AEP filed with the KPSC a cost/benefit study showing a net
benefit of approximately $13 million for KPCo over the five-year study period
from AEP's participation in PJM. In April 2004, we reached an agreement with
interveners to settle the RTO issues in Kentucky. The KPSC approved the
agreement in May 2004 and the FERC approved the settlement in June 2004.
In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to certain
conditions included in the order. The IURC's order stated that AEP shall request
and the IURC shall complete a review of Alliance formation costs before any
future recovery. I&M noted in its response to the IURC that it deferred such
costs under the July 2003 FERC order.
In November 2003, the FERC issued an order preliminarily finding that AEP must
fulfill its CSW merger condition to join an RTO by integrating into PJM
(transmission and markets) by October 1, 2004. The order was based on PURPA
205(a), which allows FERC to exempt electric utilities from state law or
regulation in certain circumstances. The FERC set several issues for public
hearing before an ALJ. Those issues include whether the laws, rules, or
regulations of Virginia and Kentucky are preventing AEP from joining an RTO and
whether the exceptions under PURPA 205(a) apply. The FERC ALJ affirmed the
FERC's preliminary findings in March 2004. The FERC issued an order related to
this matter in June 2004 affirming its preliminary findings. Virginia requested
a stay of the FERC order, which was denied, and Virginia now has requested a
stay in the courts.
FERC Order on Regional Through and Out Rates
- --------------------------------------------
In July 2003, the FERC issued an order directing PJM and the Midwest Independent
System Operator (ISO) to make compliance filings for their respective OATTs to
eliminate the transaction-based charges for through and out (T&O) transmission
service on transactions where the energy is delivered within the proposed
Midwest ISO and PJM expanded regions (RTO Footprint). The elimination of the T&O
rates will reduce the transmission service revenues collected by the RTOs and
thereby reduce the revenues received by transmission owners under the RTOs'
revenue distribution protocols. The order provided that affected transmission
owners could file to offset the elimination of these revenues by increasing
rates or utilizing a transitional rate mechanism to recover lost revenues that
result from the elimination of the T&O rates. The FERC also found that the T&O
rates of some of the former Alliance RTO companies, including AEP, may be
unjust, unreasonable, and unduly discriminatory or preferential for energy
delivered in the RTO Footprint. FERC initiated an investigation and hearing in
regard to these rates.
In November 2003, the FERC adopted a new regional rate design and directed each
transmission provider to file compliance rates to eliminate T&O rates
prospectively within the region and simultaneously implement new seams
elimination cost allocation (SECA) rates to mitigate the lost revenues for a
two-year transition period beginning April 1, 2004. The FERC was expected to
implement a new rate design after the two-year period. As required by the FERC,
we filed compliance tariff changes in January 2004 to eliminate the T&O charges
within the RTO Footprint. Various parties raised issues with the SECA rate
orders and FERC implemented settlement procedures before an ALJ.
In March 2004, the FERC approved a settlement that delays elimination of T&O
rates until December 1, 2004 and provides principles and procedures for a new
rate design for the RTO Footprint, to be effective on December 1, 2004. The
settlement also provides that if the process does not result in the
implementation of a new rate design on December 1, then the SECA rates will be
implemented and will remain in effect until a new rate is implemented by the
FERC. If implemented, the SECA rate would not be effective beyond March 31,
2006. The AEP East companies received approximately $157 million of T&O rate
revenues from transactions delivering energy to customers in the RTO Footprint
for the twelve months ended December 31, 2003. At this time, management is
unable to predict whether the new rate design will fully compensate the AEP East
companies for their lost T&O rate revenues and, consequently, their impact on
our future results of operations, cash flows and financial condition.
Indiana Fuel Order
- ------------------
On August 27, 2003, the IURC ordered that certain parties must negotiate the
appropriate action on I&M's fuel cost recovery beginning March 1, 2004,
following the February 2004 expiration of a fixed fuel adjustment charge (fixed
pursuant to a prior settlement of the Cook Nuclear Plant outage issues). The
fixed fuel adjustment charge capped fuel recoveries. In an agreement in
connection with AEP's planned corporate separation, I&M agreed, contingent on
AEP implementing the corporate separation, to a fixed fuel adjustment charge
beginning March 2004 and continuing through December 2007. Although we have not
corporately separated, certain parties believe the fixed fuel adjustment charge
should continue. Negotiations with the parties to resolve this issue are
ongoing. The IURC ordered the fixed fuel adjustment charge remain in place, on
an interim basis, for March and April 2004.
In April 2004, the IURC issued an order that extended the interim fuel factor
for May through September 2004, subject to true-up to actual fuel costs
following the resolution of issues in the corporate separation agreement. The
IURC also issued an order that reopened the corporate separation docket to
investigate issues related to the corporate separation agreement. On July 15,
2004, we filed a fuel factor for the period October 2004 through March 2005. If
the IURC reinstates a fixed fuel adjustment factor, capping the fuel revenues,
results of operations and cash flows would be adversely affected if fuel costs
are under-recovered.
Michigan 2004 Fuel Recovery Plan
- --------------------------------
A 1999 Michigan Public Service Commission's (MPSC) order approved a Settlement
Agreement regarding the extended outage of the Cook Plant and fixed I&M Power
Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers rate
areas through December 2003. As required, I&M filed its 2004 PSCR Plan with the
MPSC on September 30, 2003 seeking new fuel and power supply recovery factors to
be effective in 2004. A public hearing occurred on March 10, 2004 and a MPSC
order is expected during the second half of 2004. On June 4, 2004, an ALJ
recommended that SO2 and NOx costs be excluded. We filed our exceptions on June
18, 2004. As allowed by Michigan law, the proposed factors were effective on
January 1, 2004, subject to review and possible adjustment based on the results
of the MPSC order.
4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
------------------------------------------
As discussed in our 2003 Annual Report, we are affected by customer choice
initiatives and industry restructuring. The Customer Choice and Industry
Restructuring note in our 2003 Annual Report should be read in conjunction with
this report in order to gain a complete understanding of material customer
choice and industry restructuring matters without significant changes since
year-end. The following paragraphs discuss significant current events related to
customer choice and industry restructuring.
OHIO RESTRUCTURING
- ------------------
The Ohio Electric Restructuring Act of 1999 (Ohio Act) provides for a Market
Development Period (MDP) during which retail customers can choose their electric
power suppliers or receive Default Service at frozen generation rates from the
incumbent utility. The MDP began on January 1, 2001 and is scheduled to
terminate no later than December 31, 2005. The Public Utilities Commission of
Ohio (PUCO) may terminate the MDP for one or more customer classes before that
date if it determines either that effective competition exists in the incumbent
utility's certified territory or that there is a twenty percent switching rate
of the incumbent utility's load by customer class. Following the MDP, retail
customers will receive cost-based regulated distribution and transmission
service from the incumbent utility whose distribution rates will be approved by
the PUCO and whose transmission rates will be approved by the FERC. Retail
customers will continue to have the right to choose their electric power
suppliers or receive Default Service, which must be offered by the incumbent
utility at market rates.
On December 17, 2003, the PUCO adopted a set of rules concerning the method by
which it will determine market rates for Default Service following the MDP. The
rule provides for a Market Based Standard Service Offer (MBSSO) which would be a
variable rate based on a transparent forward market, daily market, and/or hourly
market prices. The rule also requires a fixed-rate Competitive Bidding Process
(CBP) for residential and small nonresidential customers and permits a
fixed-rate CBP for large general service customers and other customer classes.
Customers who do not switch to a competitive generation provider can choose
between the MBSSO or the CBP. Customers who make no choice will be served
pursuant to the CBP. The companies were granted a waiver from making the
required MBSSO/CBP filing, as a result of their rate stabilization plan filing.
The PUCO invited default service providers to propose an alternative to all
customers moving to market prices on January 1, 2006. On February 9, 2004, CSPCo
and OPCo filed their rate stabilization plan with the PUCO addressing prices
following the end of the MDP. If approved by the PUCO, prices would be
established pursuant to the plan for the period from January 1, 2006 through
December 31, 2008. The plan is intended to provide price stability and certainty
for customers, facilitate the development of a competitive retail market in
Ohio, provide recovery of environmental and other costs during the plan period
and improve the environmental performance of AEP's generation resources that
serve Ohio customers. The plan includes annual, fixed increases in the
generation component of all customers' bills (3% annually for CSPCo and 7%
annually for OPCo), and the opportunity for additional generation-related
increases upon PUCO review and approval. For residential customers, however, if
the temporary 5% generation rate discount provided by the Ohio Act were
eliminated prior to December 31, 2005 as permitted by the Ohio Act, the fixed
increases would be 1.6% for CSPCo and 5.7% for OPCo. Any additional
generation-related increases under the plan would be subject to caps. The plan
would maintain distribution rates through the end of 2008 for CSPCo and OPCo at
the level effective on December 31, 2005. Such rates could be adjusted for
specified reasons. Transmission charges can be adjusted to reflect applicable
charges approved by the FERC related to open access transmission, net
congestion, and ancillary services. The plan also provides for continued
recovery of transition regulatory assets and deferral of regulatory assets in
2004 and 2005 for RTO costs and carrying charges on governmentally mandated,
mainly environmental, capital expenditures. Hearings were held in June 2004.
Briefings were completed in July and the cases are pending before the PUCO.
Management cannot predict whether the plan will be approved as submitted or its
impact on results of operations and cash flows.
As provided in stipulation agreements approved by the PUCO in 2000, we are
deferring customer choice implementation costs and related carrying costs that
are in excess of $40 million. The agreements provide for the deferral of these
costs as a regulatory asset until the next distribution base rate cases. Through
June 30, 2004, we incurred $72 million, and accordingly, we deferred $32 million
of such costs. Recovery of these regulatory assets will be subject to PUCO
review in future Ohio filings for new distribution rates. If the rate
stabilization plan is approved, it would defer recovery of these amounts until
after the end of the rate stabilization period. Management believes that the
customer choice implementation costs were prudently incurred and the deferred
amounts should be recoverable in future rates. If the PUCO determines that any
of the deferred costs are unrecoverable, it would have an adverse impact on
future results of operations and cash flows.
TEXAS RESTRUCTURING
- -------------------
Texas Legislation enacted in 1999 provides the framework and timetable to allow
retail electricity competition for all Texas customers. On January 1, 2002,
customer choice of electricity supplier began in the ERCOT area of Texas.
Customer choice has been delayed in the SPP area of Texas until at least January
1, 2007.
The Texas Legislation, among other things:
o provides for the recovery of regulatory assets and other stranded costs
through securitization and non-bypassable wires charges;
o requires each utility to structurally unbundle into a retail electric
provider, a power generation company and a transmission and distribution
(T&D) utility;
o provides for an earnings test for each of the years 1999 through 2001
and;
o provides for a 2004 true-up proceeding.
The Texas Legislation required vertically integrated utilities to legally
separate their generation and retail-related assets from their transmission and
distribution-related assets. Prior to 2002, TCC and TNC functionally separated
their operations to comply with the Texas Legislation requirements. AEP formed
new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1,
2002 (the start date of retail competition). In December 2002, AEP sold the
affiliated REPs to an unaffiliated company.
TEXAS 2004 TRUE-UP PROCEEDINGS
- ------------------------------
The 2004 true-up proceedings will determine the amount and recovery of:
o net stranded generation plant costs and generation-related regulatory
assets (stranded plant costs),
o carrying charges on stranded plant costs at a weighted cost of capital from
January 2002 (the commencement date of retail competition),
o a true-up of actual market prices determined through legislatively-mandated
capacity auctions to the power costs used in the PUCT's excess cost over
market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up),
o final approved deferred fuel balance,
o unrefunded accumulated excess earnings,
o excess of price-to-beat revenues over market prices subject to certain
conditions and limitations (retail clawback) and
o other restructuring true-up items.
The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up
proceedings scheduling TCC's filing in September 2004 or 60 days after the
completion of the sale of TCC's generation assets, if later. TNC filed its 2004
true-up proceeding in June 2004.
Summary of TCC True-up Items
- ----------------------------
Amount Recorded
at June 30, 2004
----------------
(in millions)
Stranded Generation Plant Costs $1,074 (a)
Unsecuritized Transition Regulatory Asset 194 (a)
Unrefunded Excess Earnings (19) (b)
Other (46)
-------
Amount Subject to Future Securitization 1,203
-------
Wholesale Capacity Auction True-up 480 (c)
Retail Clawback (30) (d)
Deferred Over-recovered Fuel (210) (e)
-------
Other Recoverable Amounts 240
-------
Total Recorded 2004 True-up Balance $1,443 (f)
=======
(a) See "Stranded Costs and Generation-Related Regulatory Assets" section below
for additional information on this item.
(b) See "Unrefunded Excess Earnings" section below for additional information
on this item.
(c) See "Wholesale Capacity Auction True-up" section below for additional
information on this item.
(d) See "Retail Clawback" section below for additional information on this item.
(e) See "Fuel Balance Recoveries" section below for additional information on
this item.
(f) See "Stranded Cost Recovery" section below for summary of this balance.
Stranded Costs and Generation-Related Regulatory Assets
- -------------------------------------------------------
Restructuring legislation required utilities with stranded costs to use
market-based methods to value certain generation assets for determining stranded
costs. TCC is the only AEP subsidiary that has stranded costs under the Texas
Legislation. We elected to use the sale of assets method to determine the market
value of TCC's generation assets for stranded cost purposes. For purposes of the
2004 true-up proceeding, the amount of stranded costs under this market
valuation methodology will be the amount by which the book value of TCC's
generation assets, including regulatory assets and liabilities that were not
securitized, exceeds the market value of the generation assets as measured by
the net proceeds from the sale of the assets. Based on the prices established by
the sales, discussed below, TCC's stranded costs from the sale of TCC's
generation assets and remaining generation-related net regulatory assets are
estimated to be $1.3 billion ($1,074 million and $194 million, described later
in this section) before accrual of any applicable carrying charges.
In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's
generation capacity in Texas with a net book value of $1.9 billion at June 30,
2004. We received bids for all of TCC's generation plants. In January 2004, TCC
agreed to sell its 7.81% ownership interest in the Oklaunion Power Station to an
unaffiliated third party for approximately $43 million. In March 2004, TCC
agreed to sell its 25.2% ownership interest in STP for approximately $333
million and its other coal, gas and hydro plants for approximately $430 million
to unaffiliated entities. Each sale is subject to specified price adjustments.
TCC sent right of first refusal notices to the co-owners of Oklaunion and STP.
TCC filed for FERC approval of the sales of Oklaunion and the fossil and hydro
plants. We have received a notice from co-owners of Oklaunion and STP exercising
their right of first refusal; therefore, SEC approval will be required. The
original unaffiliated third party purchaser of Oklaunion has petitioned for a
court order declaring its contract valid and that the co-owners' rights of first
refusal are void. Approval of the sale of STP from the Nuclear Regulatory
Commission is required. On July 1, 2004, we completed the sale of the other
coal, gas and hydro plants for approximately $425 million, net of adjustments.
The completion of the sales of STP and Oklaunion plants is expected to occur in
2004, subject to the rights of first refusal and the necessary regulatory
approvals. In order to sell these assets, TCC defeased all of its remaining
outstanding first mortgage bonds in May 2004. TCC will file its 2004 true-up
proceeding with the PUCT after the completion of the sale of the generation
assets.
After the 2004 true-up proceeding, TCC may recover stranded costs and other
true-up amounts through distribution rates as a competition transition charge
and may seek to issue securitization revenue bonds for its stranded plant costs
and remaining generation net regulatory assets. The cost of the securitization
bonds is recovered through distribution rates as a separate transition charge.
We recognized an impairment of TCC's generation assets in December 2003 as a
regulatory asset. At June 30, 2004, this regulatory asset was approximately
$1,074 million. The recovery of this regulatory asset and the remaining $194
million of generation-related net regulatory assets will be subject to review
and approval by the PUCT as a stranded plant cost in the 2004 true-up
proceeding.
Carrying Charges On Recoverable Stranded Costs
- ----------------------------------------------
In December 2001, the PUCT issued a rule concerning stranded cost true-up
proceedings stating, among other things, that carrying costs on stranded costs
would begin to accrue on the date that the PUCT issued its final order in the
2004 true-up proceeding. TCC and one other Texas electric utility company filed
a direct appeal of the rule to the Texas Third Court of Appeals contending that
carrying costs should commence on January 1, 2002, the day that retail customer
choice began in ERCOT.
The Third Court of Appeals ruled against the companies, who then appealed to the
Texas Supreme Court. On June 18, 2004, the Texas Supreme Court reversed the
decision of the Third Court of Appeals determining that a carrying cost should
be accrued beginning January 1, 2002 and remanded the proceeding to the PUCT for
further consideration. The Supreme Court determined that utilities with stranded
costs are not permitted to over-recover stranded costs and the PUCT should
address whether the 2002 and 2003 wholesale capacity auction true-up regulatory
asset includes a recovery of stranded costs. Industrial intervenors have filed a
motion for rehearing with the Supreme Court which has not been decided.
The PUCT has indicated that it will consider the Supreme Court's decision in
hearings to be held for another utility in September 2004. The decision in that
proceeding could have an impact on TCC. Since the impact of these future PUCT
proceedings cannot be determined at this time, TCC has not recorded the carrying
charge as a regulatory asset through June 30, 2004.
Wholesale Capacity Auction True-up
- ----------------------------------
Texas Legislation required that electric utilities and their affiliated power
generation companies (PGC) offer for sale at auction, in 2002 and 2003 and
after, at least 15% of the PGC's Texas jurisdictional installed generation
capacity in order to promote competitiveness in the wholesale market through
increased availability of generation. Actual market power prices received in the
state-mandated auctions will be used to calculate the wholesale capacity auction
true-up adjustment for TCC for the 2004 true-up proceeding. According to PUCT
rules, the wholesale capacity auction true-up is only applicable to the years
2002 and 2003. TCC recorded a $480 million regulatory asset and related revenues
which represent the quantifiable amount of the wholesale capacity auction
true-up for the years 2002 and 2003.
In the fourth quarter of 2003, the PUCT approved a true-up filing package
containing calculation instructions similar to the methodology employed by TCC
to calculate the amount recorded for recovery under its wholesale capacity
auction true-up. The PUCT will review the $480 million wholesale capacity
auction true-up regulatory asset for recovery as part of the 2004 true-up
proceeding.
Fuel Balance Recoveries
- -----------------------
In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail sales
within its ERCOT service area for inclusion in the 2004 true-up proceeding. In
January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation
case. The PUCT issued a written order in March 2004 that established TNC's
unrecovered fuel balance for the ERCOT service territory. Various parties,
including TNC, requested rehearing of the PUCT's order. In May 2004, the PUCT
reversed certain prior rulings resulting in TNC having a final fuel
over-recovery balance of approximately $7 million. TNC's 2004 true-up
proceeding, filed in June 2004, will be updated to reflect the balance after the
PUCT issues a final fuel order. TNC has provided for all to-date disallowances
pending receipt of the final order. Management is unable to predict the amount
of TNC's fuel over-recovery which will be included in its 2004 true-up
proceedings.
In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its
deferred over-recovery of fuel balance for inclusion in the 2004 true-up
proceeding. In May 2004, the PUCT remanded TCC's fuel proceeding to the ALJ. TCC
has provided $210 million for its over-recovery balance at June 30, 2004. TCC
has provided for all to-date disallowances pending receipt of a final order.
Management is unable to predict the amount of TCC's fuel over-recovery which
will be included in its 2004 true-up proceeding.
See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 3 "Rate Matters"
for further discussion.
Unrefunded Excess Earnings
- --------------------------
The Texas Legislation provides for the calculation of excess earnings for each
year from 1999 through 2001. The total excess earnings determined for the three
year period were $3 million for SWEPCo, $47 million for TCC and $19 million for
TNC. TCC, TNC and SWEPCo challenged the PUCT's treatment of fuel-related
deferred income taxes and appealed the PUCT's final 2000 excess earnings to the
Travis County District Court which upheld the PUCT ruling. The District Court's
ruling was appealed to the Third Court of Appeals. In August 2003, the Third
Court of Appeals reversed the PUCT order and the District Court's judgment. The
PUCT's request for rehearing of the Appeals Court's decision was denied and the
PUCT chose not to appeal the ruling any further. The District Court remanded to
the PUCT an appeal of the same issue from the PUCT's 2001 order to be consistent
with the Court of Appeals decision. Since an expense and regulatory liability
had been accrued in prior years in compliance with the PUCT orders, the
companies reversed a portion of their regulatory liability for the years 2000
and 2001 consistent with the Appeals Court's decision and credited amortization
expense during the third quarter of 2003.
In 2001, the PUCT issued an order requiring TCC to return estimated excess
earnings by reducing distribution rates by approximately $55 million plus
accrued interest over a five-year period beginning January 1, 2002. Since excess
earnings amounts were expensed in 1999, 2000 and 2001, the order had no
additional effect on reported net income but will reduce cash flows for the
five-year refund period. The amount to be refunded is recorded as a regulatory
liability ($19 million at June 30, 2004). Management believes that TCC will have
stranded costs and that it was inappropriate for the PUCT to order a refund
prior to TCC's 2004 true-up proceeding. TCC appealed the PUCT's refund of excess
earnings to the Travis County District Court. That court affirmed the PUCT's
decision and further ordered that the refunds be provided to ultimate customers.
TCC has appealed the decision to the Court of Appeals.
Retail Clawback
- ---------------
The Texas Legislation provides for the affiliated price-to-beat (PTB) retail
electric providers (REP) serving residential and small commercial customers to
refund to its T&D utility the excess of the PTB revenues over market prices
(subject to certain conditions and a limitation of $150 per customer). This is
the retail clawback. If, prior to January 1, 2004, 40% of the load for the
residential or small commercial classes is served by competitive REPs, the
retail clawback is not applicable for that class of customer. During 2003, TCC
and TNC filed to notify the PUCT that competitive REPs serve over 40% of the
load in the small commercial class. The PUCT approved TCC's and TNC's filings in
December 2003. In 2002, AEP had accrued a regulatory liability of approximately
$9 million for the small commercial retail clawback on its REP's books. When the
PUCT certified that the REP's in TCC and TNC service territories had reached the
40% threshold, the regulatory liability was no longer required for the small
commercial class and was reversed in December 2003. Based upon customer
information filed by the unaffiliated company which operates as the affiliated
REP for TCC and TNC, we updated the estimated retail clawback regulatory
liability in May 2004. At June 30, 2004, AEP's retail clawback regulatory
liability was $37 million ($30 million related to TCC and $7 million related to
TNC).
TNC 2004 True-up Filing
- -----------------------
In June 2004, TNC filed its 2004 true-up proceeding including the fuel
reconciliation balance and the retail clawback calculation. The amount of
deferred fuel, presently an over-recovery balance of $7 million, remains under
review by the PUCT and is subject to possible revision. The retail clawback
regulatory liability was adjusted in the second quarter of 2004 to $7 million
(TNC's allocated portion of the REP's retail clawback) reflecting the number of
customers served on January 1, 2004. The PUCT has deferred this proceeding
pending the resolution of the final fuel proceeding.
Stranded Cost Recovery
- ----------------------
When the 2004 true-up proceeding is completed, TCC intends to file to recover
PUCT-approved stranded costs and other true-up amounts that are in excess of
current securitized amounts, plus appropriate carrying charges, through a
non-bypassable competition transition charge in the regulated rates. TCC may
also seek to securitize the approved stranded plant costs and generation-related
net regulatory assets that were not previously recovered through a prior
securitization and the non-bypassable transition charge. The annual costs of
securitization are recovered through the non-bypassable transition charge
collected by the T&D utility over the term of the securitization bonds.
TCC's recorded net regulatory asset for stranded cost in the 2004 true-up
proceeding is approximately $1.4 billion. We estimate that TCC's 2004 true-up
filing will exceed the total of its recorded net regulatory asset. Management
expects that the 2004 true-up proceeding will be contentious and could possibly
result in disallowances.
In the event we are unable, after the 2004 true-up proceeding, to recover all or
a portion of our stranded plant costs, generation-related net regulatory assets,
wholesale capacity auction true-up regulatory assets, other restructuring
true-up items and costs, it could have a material adverse effect on results of
operations, cash flows and possibly financial condition.
VIRGINIA RESTRUCTURING
- ----------------------
In April 2004, the Governor of Virginia signed legislation which extends the
transition period for electricity restructuring, including capped rates, through
December 31, 2010. The legislation provides specified cost recovery
opportunities during the capped rate period, including two optional general base
rate changes and an opportunity for recovery, through a separate rate mechanism,
of incremental environmental and reliability costs.
5. COMMITMENTS AND CONTINGENCIES
-----------------------------
As discussed in the Commitments and Contingencies note within our 2003 Annual
Report, we continue to be involved in various legal matters. The 2003 Annual
Report should be read in conjunction with this report in order to understand the
other material nuclear and operational matters without significant changes since
our disclosure in the 2003 Annual Report. The material matters discussed in the
2003 Annual Report without significant changes in status since year-end include,
but are not limited to, (1) nuclear matters, (2) construction commitments, (3)
potential uninsured losses, (4) merger litigation, (5) shareholder lawsuits, (6)
California lawsuits, (7) Cornerstone lawsuit, (8) Bank of Montreal Claim, and
(9) FERC proposed Standard Market Design. See disclosure below for significant
matters with changes in status subsequent to the disclosure made in our 2003
Annual Report.
ENVIRONMENTAL
- -------------
Federal EPA Complaint and Notice of Violation
- ---------------------------------------------
The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and
other unaffiliated utilities modified certain units at coal-fired generating
plants in violation of the new source review requirements of the Clean Air Act
(CAA). The Federal EPA filed its complaints against our subsidiaries in U.S.
District Court for the Southern District of Ohio. The court also consolidated a
separate lawsuit, initiated by certain special interest groups, with the Federal
EPA case. The alleged modifications relate to costs that were incurred at our
generating units over a 20-year period.
Under the CAA, if a plant undertakes a major modification that directly results
in an emissions increase, permitting requirements might be triggered and the
plant may be required to install additional pollution control technology. This
requirement does not apply to activities such as routine maintenance,
replacement of degraded equipment or failed components, or other repairs needed
for the reliable, safe and efficient operation of the plant. The CAA authorizes
civil penalties of up to $27,500 per day per violation at each generating unit
($25,000 per day prior to January 30, 1997). In 2001, the District Court ruled
claims for civil penalties based on activities that occurred more than five
years before the filing date of the complaints cannot be imposed. There is no
time limit on claims for injunctive relief.
On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to
"perfect" its complaint in the pending litigation. The NOV expands the number of
alleged "modifications" undertaken at the Muskingum River, Cardinal, Conesville
and Tanners Creek plants during scheduled outages on these units from 1979
through the present. Approximately one-third of the allegations in the NOV are
already contained in allegations made by the states or the special interest
groups in the pending litigation. The Federal EPA is expected to file a motion
to amend its complaint, and, to the extent that motion seeks to expand the scope
of the pending litigation, the AEP subsidiaries will oppose that motion.
On August 7, 2003, the District Court issued a decision following a liability
trial in a case pending in the Southern District of Ohio against Ohio Edison
Company, an unaffiliated utility. The District Court held that replacements of
major boiler and turbine components that are infrequently performed at a single
unit, that are performed with the assistance of outside contractors, that are
accounted for as capital expenditures, and that require the unit to be taken out
of service for a number of months are not "routine" maintenance, repair, and
replacement. The District Court also held that a comparison of past actual
emissions to projected future emissions must be performed prior to any
non-routine physical change in order to evaluate whether an emissions increase
will occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all of the
challenged activities in that case were not routine, and that the changes
resulted in significant net increases in emissions for certain pollutants. A
remedy trial was scheduled for July 2004, but has been postponed until January
2005 to facilitate further settlement negotiations.
Management believes that the Ohio Edison decision fails to properly evaluate and
apply the applicable legal standards. The facts in our case also vary widely
from plant to plant. Further, the Ohio Edison decision is limited to liability
issues, and provides no insight as to the remedies that might ultimately be
ordered by the Court.
On August 26, 2003, the District Court for the Middle District of South Carolina
issued a decision on cross-motions for summary judgment prior to a liability
trial in a case pending against Duke Energy Corporation, an unaffiliated
utility. The District Court denied all the pending motions, but set forth the
legal standards that will be applied at the trial in that case. The District
Court determined that the Federal EPA bears the burden of proof on the issue of
whether a practice is "routine maintenance, repair, or replacement" and on
whether or not a "significant net emissions increase" results from a physical
change or change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the relevant
source category" in determining if it is "routine." Further, the Federal EPA
must calculate emissions by determining first whether a change in the maximum
achievable hourly emission rate occurred as a result of the change, and then
must calculate any change in annual emissions holding hours of operation
constant before and after the change. The Federal EPA requested reconsideration
of this decision, or in the alternative, certification of an interlocutory
appeal to the Fourth Circuit Court of Appeals, and the District Court denied the
Federal EPA's motion. On April 13, 2004, the parties filed a joint motion for
entry of final judgment, based on stipulations of relevant facts that obviated
the need for a trial, but preserving plaintiffs' right to seek an appeal of the
federal prevention of significant deterioration (PSD) claims. On April 14, 2004,
the Court entered final judgment for Duke Energy on all of the PSD claims made
in the amended complaints, and dismissed all remaining claims with prejudice.
The United States subsequently filed a notice of appeal to the Fourth Circuit
Court of Appeals, which issued a briefing order requiring the case to be fully
briefed by late September 2004.
On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued
an order invalidating the administrative compliance order issued by the Federal
EPA to the Tennessee Valley Authority for alleged CAA violations. The 11th
Circuit determined that the administrative compliance order was not a final
agency action, and that the enforcement provisions authorizing the issuance and
enforcement of such orders under the CAA are unconstitutional. The United States
filed a petition for certiorari with the United States Supreme Court and on May
3, 2004, that petition was denied.
On June 26, 2003, the United States Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG),
of which our subsidiaries are members, to reopen petitions for review of the
1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA
claims in our case and other related cases. On August 4, 2003, UARG filed a
motion to separate and expedite review of their challenges to the 1980 and 1992
rulemakings from other unrelated claims in the consolidated appeal. The Circuit
Court denied that motion on September 30, 2003. The central issue in these
petitions concerns the lawfulness of the emissions increase test, as currently
interpreted and applied by the Federal EPA in its utility enforcement actions. A
decision by the D. C. Circuit Court could significantly impact further
proceedings in our case.
On August 27, 2003, the Administrator of the Federal EPA signed a final rule
that defines "routine maintenance repair and replacement" to include
"functionally equivalent equipment replacement." Under the new final rule,
replacement of a component within an integrated industrial operation (defined as
a "process unit") with a new component that is identical or functionally
equivalent will be deemed to be a "routine replacement" if the replacement does
not change any of the fundamental design parameters of the process unit, does
not result in emissions in excess of any authorized limit, and does not cost
more than twenty percent of the replacement cost of the process unit. The new
rule is intended to have a prospective effect, and was to become effective in
certain states 60 days after October 27, 2003, the date of its publication in
the Federal Register, and in other states upon completion of state processes to
incorporate the new rule into state law. On October 27, 2003 twelve states, the
District of Columbia and several cities filed an action in the United States
Court of Appeals for the District of Columbia Circuit seeking judicial review of
the new rule. The UARG has intervened in this case. On December 24, 2003, the
Circuit Court granted a motion from the petitioners to stay the effective date
of this rule, which had been December 26, 2003.
We are unable to estimate the loss or range of loss related to any contingent
liability we might have for civil penalties under the CAA proceedings. We are
also unable to predict the timing of resolution of these matters due to the
number of alleged violations and the significant number of issues yet to be
determined by the Court. If we do not prevail, any capital and operating costs
of additional pollution control equipment that may be required, as well as any
penalties imposed, would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity.
In December 2000, Cinergy Corp., an unaffiliated utility, which operates certain
plants jointly owned by CSPCo, reached a tentative agreement with the Federal
EPA and other parties to settle litigation regarding generating plant emissions
under the Clean Air Act. Negotiations are continuing between the parties in an
attempt to reach final settlement terms. Cinergy's settlement could impact the
operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned
25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached,
CSPCo will be unable to determine the settlement's impact on its jointly owned
facilities and its future results of operations and cash flows.
On July 21, 2004, the Sierra Club issued a notice of intent to file a citizen
suit claim against DPL, Inc., Cinergy Corporation, CSPCo, and The Dayton Power &
Light Company for alleged violations of the New Source Review programs at the
Stuart Station. CSPCo owns a 26% share of the Stuart Station. Management is
unable to predict the timing of any future action by the special interest group
or the effect of such actions on future operations or cash flows.
SWEPCo Notice of Enforcement and Notice of Citizen Suit
- -------------------------------------------------------
On July 13, 2004, two special interest groups issued a notice of intent to
commence a citizen suit under the Clean Air Act for alleged violations of
various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and
Pirkey plants. This notice was prompted by allegations made by a terminated
AEP employee. The allegations at the Welsh Plant concern compliance with
emission limitations on particulate matter and carbon monoxide, compliance with
a referenced design heat input 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, financial condition or cash flows.
Carbon Dioxide Public Nuisance Claims
- -------------------------------------
On July 21, 2004, attorneys general from eight states and the corporation
counsel for the City of New York filed an action in federal district court for
the Southern District of New York against AEP, AEPSC and four other unaffiliated
governmental and investor-owned electric utility systems. That same day, a
similar complaint was filed in the same court against the same defendants by the
Natural Resources Defense Council on behalf of two special interest groups. The
actions allege that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts associated
with global warming, and seek injunctive relief in the form of specific emission
reduction commitments from the defendants. Management believes the actions are
without merit and intends to vigorously defend against the claims.
Nuclear Decommissioning
- -----------------------
As discussed in the 2003 Annual Report, decommissioning costs are accrued over
the service life of STP. The licenses to operate the two nuclear units at STP
expire in 2027 and 2028. TCC had estimated its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of approximately $8 million per year.
In May 2004, an updated decommissioning study was completed for STP. The study
estimates TCC's share of the decommissioning costs of STP to be $344 million in
nondiscounted 2004 dollars. As discussed in Note 7, TCC is in the process of
selling its ownership interest in STP to a non-affiliate, and upon completion of
the sale it is anticipated that TCC will no longer be obligated for nuclear
decommissioning liabilities associated with STP.
OPERATIONAL
- -----------
Power Generation Facility
- -------------------------
We have agreements with Juniper Capital L.P. (Juniper) under which Juniper
constructed and financed a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and leased the Facility to us. We have
subleased the Facility to the Dow Chemical Company (Dow). The Facility is a
Dow-operated "qualifying cogeneration facility" for purposes of PURPA.
Commercial operation of the Facility as required by the agreements between
Juniper, AEP and Dow was achieved on March 18, 2004. The initial term of our
lease with Juniper (Juniper Lease) commenced on March 18, 2004 and terminates on
June 17, 2009. We may extend the term of the Juniper Lease for up to 30 years.
Our lease of the Facility is reported as an owned asset under a lease financing
transaction. Therefore, the asset and related liability for the debt and equity
of the facility are recorded on 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 on the fair
value of the assets at that time. However, if we default under the Juniper
Lease, our maximum cash payment could be as much as $525 million.
Dow uses a portion of the energy produced by the Facility and sells the excess
energy. OPCo has agreed to purchase up to approximately 800 MW of such excess
energy from Dow. Because the Facility is a major steam supply for Dow, Dow is
expected to operate the Facility at certain minimum levels, and OPCo is
obligated to purchase the energy generated at those minimum operating levels
(expected to be approximately 270 MW).
OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel
Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and
Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in
excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity,
energy and ancillary services to TEM pursuant to the PPA that TEM rejected as
non-conforming. Commercial operation for purposes of the PPA began April 2,
2004.
On September 5, 2003, TEM and AEP separately filed declaratory judgment actions
in the United States District Court for the Southern District of New York. We
allege that TEM has breached the PPA, and we are seeking a determination of our
rights under the PPA. TEM alleges that the PPA never became enforceable, or
alternatively, that the PPA has already been terminated as the result of AEP
breaches. If the PPA is deemed terminated or found to be unenforceable by the
court, we could be adversely affected to the extent we are unable to find other
purchasers of the power with similar contractual terms and to the extent we do
not fully recover claimed termination value damages from TEM. The corporate
parent of TEM (Tractebel SA) has provided a limited guaranty.
On November 18, 2003, the above litigation was suspended pending final
resolution in arbitration of all issues pertaining to the protocols relating to
the dispatching, operation, and maintenance of the Facility and the sale and
delivery of electric power products. In the arbitration proceedings, TEM argued
that in the absence of mutually agreed upon protocols there were no commercially
reasonable means to obtain or deliver the electric power products and therefore
the PPA is not enforceable. TEM further argued that the creation of the
protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on
February 11, 2004 and concluded that the "creation of protocols" was not subject
to arbitration, but did not rule upon the merits of TEM's claim that the PPA is
not enforceable. Management believes the PPA is enforceable. The litigation is
now in the discovery phase.
On March 26, 2004, OPCo requested that TEM provide assurances of performance of
its future obligations under the PPA, but TEM refused to do so. As indicated
above, OPCo also gave notice to TEM and declared April 2, 2004 as the
"Commercial Operations Date." Despite OPCo's prior tenders of replacement
electric power products to TEM beginning May 1, 2003 and despite OPCo's tender
of electric power products from the Facility to TEM beginning April 2, 2004, TEM
refused to accept and pay for them under the terms of the PPA. On April 5, 2004,
OPCo gave notice to TEM that OPCo (i) was suspending performance of its
obligations under 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.
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 Investigation
- ---------------------------
AEP and other energy market participants received data requests, subpoenas and
requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity
Futures Trading Commission (CFTC), the U.S. Department of Justice and the
California attorney general during 2002. Management responded to the inquiries
and provided the requested information and has continued to respond to
supplemental data requests in 2003 and 2004.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in
federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES
provided false or misleading information about market conditions and prices of
natural gas in an attempt to manipulate the price of natural gas in violation of
the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and
disgorgement of benefits. 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 what,
if any further action, any of these governmental agencies may take with respect
to these matters.
FERC Market Power Mitigation
- ----------------------------
A FERC order issued in November 2001 on AEP's triennial market based wholesale
power rate authorization update required certain mitigation actions that AEP
would need to take for sales/purchases within its control area and required AEP
to post information on its website regarding its power system's status. As a
result of a request for rehearing filed by AEP and other market participants,
FERC issued an order delaying the effective date of the mitigation plan until
after a planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. In April 2004, the FERC issued two orders concerning
utilities' ability to sell wholesale electricity at market-based rates. In the
first order, the FERC adopted two new interim screens for assessing potential
generation market power of applicants for wholesale market based rates, and
described additional analyses and mitigation measures that could be presented if
an applicant does not pass one of these interim screens. In July 2004, the FERC
issued an order on rehearing affirming its conclusions in the April order and
directing AEP and two unaffiliated utilities to file generation market power
analyses within 30 days. In the second order, the FERC initiated a rulemaking to
consider whether the FERC's current methodology for determining whether a public
utility should be allowed to sell wholesale electricity at market-based rates
should be modified in any way. We plan to present evidence to demonstrate that
we do not possess market power in geographic areas where we sell wholesale
power.
6. GUARANTEES
----------
There are certain immaterial liabilities recorded for guarantees entered into
subsequent to December 31, 2002 in accordance with FIN 45. There is no
collateral held in relation to any guarantees in excess of our ownership
percentages and there is no recourse to third parties in the event any
guarantees are drawn unless specified below.
LETTERS OF CREDIT
- -----------------
We have entered into standby letters of credit (LOC) with third parties. These
LOCs cover gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits, debt service reserves and
credit enhancements for issued bonds. All of these LOCs were issued by us in the
ordinary course of business. At June 30, 2004, the maximum future payments for
all the LOCs were approximately $244 million with maturities ranging from July
2004 to January 2011. As the parent of various subsidiaries, we hold all assets
of the subsidiaries as collateral. There is no recourse to third parties in the
event these letters of credit are drawn.
We have guaranteed 50% of the principal and interest payments as well as 100% of
a Power Purchase Agreement (PPA) of the Fort Lupton, Colorado IPP (also known as
Thermo), of which we are a 50% owner. In the event Fort Lupton does not make the
required debt payments, we have a maximum future payment exposure of
approximately $7 million, which expires May 2008. In the event Fort Lupton is
unable to perform under its PPA agreement, we have a maximum future payment
exposure of approximately $15 million, which expires June 2019. We will be
released from this guarantee upon the anticipated sale of this IPP. See Note 7
regarding the sale of IPPs, of which Fort Lupton is included. Our exposure for
these payments will expire upon the sale of Fort Lupton in the third quarter of
2004.
We had a letter of credit for Orange Cogeneration, a cogeneration plant located
in Bartow, Florida, that expired upon its sale in July 2004. See Note 7.
GUARANTEES OF THIRD-PARTY OBLIGATIONS
- -------------------------------------
CSW Energy and CSW International
- --------------------------------
CSW Energy and CSW International, AEP subsidiaries, have guaranteed 50% of the
required debt service reserve of Sweeny Cogeneration L.P. (Sweeny), an IPP of
which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny
funding the debt reserve as a part of a financing. In the event that Sweeny does
not make the required debt payments, CSW Energy and CSW International have a
maximum future payment exposure of approximately $4 million, which expires June
2020.
AEP Utilities
- -------------
AEP Utilities was released from its guarantee for Mulberry, a cogeneration plant
located in Bartow, Florida, when it was sold in July 2004. See Note 7.
SWEPCo
- ------
In connection with reducing the cost of the lignite mining contract for its
Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain conditions, to
assume the capital lease obligations and term loan payments of the mining
contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under
any of these agreements, SWEPCo's total future maximum payment exposure is
approximately $51 million with maturity dates ranging from June 2005 to February
2012.
As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, SWEPCo has agreed to provide guarantees of mine
reclamation in the amount of approximately $85 million. Since SWEPCo uses
self-bonding, the guarantee provides for SWEPCo to commit to use its resources
to complete the reclamation in the event the work is not completed by a third
party miner. At June 30, 2004, the cost to reclaim the mine in 2035 is estimated
to be approximately $36 million. This guarantee ends upon depletion of reserves
estimated at 2035 plus 6 years to complete reclamation.
As of July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46.
SWEPCo does not have an ownership interest in Sabine.
INDEMNIFICATIONS AND OTHER GUARANTEES
- -------------------------------------
Contracts
- ---------
We entered into several types of contracts which require indemnifications.
Typically these contracts include, but are not limited to, sale agreements,
lease agreements, purchase agreements and financing agreements. Generally these
agreements may include, but are not limited to, indemnifications around certain
tax, contractual and environmental matters. With respect to sale agreements, our
exposure generally does not exceed the sale price. We cannot estimate the
maximum potential exposure for any of these indemnifications entered into prior
to December 31, 2002 due to the uncertainty of future events. In 2003 and during
the first six months of 2004, we entered into several sale agreements. These
sale agreements include indemnifications with a maximum exposure of
approximately $258 million. There are no material liabilities recorded for any
indemnifications entered into during 2003 or the first six months 2004. There
are no liabilities recorded for any indemnifications entered prior to December
31, 2002.
Master Operating Lease
- ----------------------
We lease certain equipment under a master operating lease. Under the lease
agreement, the lessor is guaranteed to receive up to 87% of the unamortized
balance of the equipment at the end of the lease term. If the fair market value
of the leased equipment is below the unamortized balance at the end of the lease
term, we have committed to pay the difference between the fair market value and
the unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At June 30, 2004, the maximum potential loss for these
lease agreements was approximately $35 million ($23 million, net of tax)
assuming the fair market value of the equipment is zero at the end of the lease
term.
Railcar Lease
- -------------
In June 2003, we entered into an agreement with an unrelated, unconsolidated
leasing company to lease 875 coal-transporting aluminum railcars. The lease has
an initial term of five years and may be renewed for up to three additional
five-year terms, for a maximum of twenty years.
Under the lease agreement, the lessor is guaranteed that the sale proceeds under
a return-and-sale option will equal at least a lessee obligation amount
specified in the lease, which declines over the term from approximately 86% to
77% of the projected fair market value of the equipment. At June 30, 2004, the
maximum potential loss was approximately $31.5 million ($20.5 million, net of
tax) assuming the fair market value of the equipment is zero at the end of the
current lease term. The railcars are subleased for one year terms to an
unaffiliated company under an operating lease. The sublessee has recently
renewed for an additional year and may renew the lease for up to three more
additional one-year terms.
7. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE
--------------------------------------------------------------
DISPOSITION COMPLETED DURING FIRST QUARTER 2004
- -----------------------------------------------
Pushan Power Plant (Investments - Other segment)
- ------------------------------------------------
In the fourth quarter of 2002, we began active negotiations to sell our interest
in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest
partner and a purchase and sale agreement was signed in the fourth quarter of
2003. The sale was completed in March 2004 for $60.7 million. An estimated
pre-tax loss on disposal of $20 million pre-tax ($13 million after-tax) was
recorded in December 2002, based on an indicative price expression at that time,
and was classified in Discontinued Operations. The effect of the sale on the
first quarter 2004 results of operations was not significant.
Results of operations of Pushan have been reclassified as Discontinued
Operations. The assets and liabilities of Pushan were classified on our
Consolidated Balance Sheets as held for sale until the sale was complete.
Beginning with our first quarter 2004 financial statements, the assets and
liabilities of Pushan are shown as Assets of Discontinued Operations and
Liabilities of Discontinued Operations for all periods presented.
DISPOSITIONS COMPLETED DURING SECOND QUARTER 2004
- -------------------------------------------------
LIG Pipeline Company and its Subsidiaries (Investments - Gas Operations segment)
- --------------------------------------------------------------------------------
In February 2004, we signed an agreement to sell LIG Pipeline Company, which
includes approximately 2,000 miles of natural gas gathering and transmission
pipelines in Louisiana and five gas processing facilities that straddle the
system. The sale of LIG Pipeline Company and its assets for $76.2 million was
completed in April 2004. The effect of the sale on the second quarter 2004
results of operations was not significant.
Results of operations of LIG Pipeline Company were reclassified as of December
31, 2003 as Discontinued Operations. The assets and liabilities of LIG Pipeline
Company were classified on our Balance Sheet as held for sale until the sale was
complete. Beginning with our second quarter 2004 financial statements, the
assets and liabilities of LIG Pipeline Company are shown as Assets of
Discontinued Operations and Liabilities of Discontinued Operations for all
periods presented.
See Louisiana Intrastate Gas (LIG) in Discontinued Operations section of this
note for previous impairments taken on the LIG assets and information regarding
remaining LIG assets still held for sale.
AEP Coal (Investments - Other segment)
- --------------------------------------
In 2003, as a result of management's decision to exit our non-core businesses,
we retained an advisor to facilitate the sale of AEP Coal. In March 2004, an
agreement was reached to sell assets, exclusive of certain reserves and related
liabilities, of the mining operations of AEP Coal. AEP received approximately
$8.8 million cash and the buyer assumed an additional $11.1 million in future
reclamation liability. AEP has retained an estimated $36.7 million in future
reclamation liabilities. The sale closed in April 2004 and the effect of the
sale on second quarter 2004 results of operations was not significant. The
assets and liabilities of AEP Coal that were held for sale have been included in
Assets Held for Sale and Liabilities Held for Sale in our Consolidated Balance
Sheets at December 31, 2003.
DISPOSITIONS COMPLETED OR SCHEDULED TO BE COMPLETED DURING SECOND HALF 2004
- ---------------------------------------------------------------------------
Texas Plants (Utility Operations segment)
- -----------------------------------------
In December 2002, TCC filed a plan of divestiture with the PUCT proposing to
sell all of its power generation assets, including the eight gas-fired
generating plants that were either deactivated or designated as "reliability
must run" status.
During the fourth quarter of 2003, after receiving bids from interested buyers,
we recorded a $938 million impairment loss and changed the classification of the
plant assets from plant in service to Assets Held for Sale. In accordance with
Texas legislation, the $938 million impairment was offset by the establishment
of a regulatory asset, which is expected to be recovered through a wires charge,
subject to the final outcome of the 2004 Texas true-up proceeding. As a result
of the 2004 true-up proceeding, if we are unable to recover all or a portion of
our requested costs (see Note 4), any unrecovered costs could have a material
adverse effect on our results of operations, cash flows and possibly financial
condition.
During early 2004, we signed agreements to sell all of our TCC generating
assets, at prices which approximate book value after considering the impairment
charge described above. As a result, we do not expect these pending asset sales,
described below, to have a significant effect on our future results of
operations, except in the case that our true-up proceedings, as described above,
do not allow for recovery of our stranded costs.
Oklaunion Power Station
-----------------------
In April 2004, we signed an agreement to sell TCC's 7.81 percent share of
Oklaunion Power Station for approximately $43 million (subject to closing
adjustments) to an unrelated party. In May 2004, we received notice from
the two co-owners of the Oklaunion Power Station, announcing their
decision to exercise their right of first refusal, with terms similar to
the original agreement. The sale is currently being challenged by the
unrelated party with which we entered into the original sales agreement.
The unrelated party alleges that one of two co-owners has exceeded its
legal authority and has requested that the court declare the one
co-owner's exercise of its right of first refusal void. The unrelated
party further argues that the second of the two co-owner's exercise of its
right of first refusal is not timely and invalid. We expect that this
legal issue will be resolved and that the planned sale will close by the
end of 2004.
South Texas Project
-------------------
In February 2004, we signed an agreement to sell TCC's 25.2 percent share
of the South Texas Project (STP) nuclear plant for approximately $333
million, subject to closing adjustments. In June 2004, we received notice
from co-owners of their decisions to exercise their rights of first
refusal, with terms similar to the original agreement. We expect the sale
to close before the end of 2004 subject to necessary regulatory approval.
TCC Generation Assets
---------------------
In March 2004, we signed an agreement to sell our remaining generating
assets within TCC, including eight natural gas plants, one coal-fired
plant and one hydro plant to a non-related joint venture. The sale was
completed in July 2004 for approximately $425 million, net of adjustments.
The sale did not have a significant effect on our results of operations
during the second quarter 2004.
Independent Power Producers (Investments - Other segment)
- ---------------------------------------------------------
During the third quarter of 2003, we initiated an effort to sell four domestic
Independent Power Producer (IPP) investments accounted for under the equity
method (two located in Colorado and two located in Florida). Our two Colorado
investments include a 47.75 percent interest in Brush II, a 68-megawatt,
gas-fired, combined cycle, cogeneration plant in Brush, Colorado and a 50
percent interest in Thermo, a 272-megawatt, gas-fired, combined cycle,
cogeneration plant located in Ft. Lupton, Colorado. Our two Florida investments
include a 46.25 percent interest in Mulberry, a 120-megawatt, gas-fired,
combined cycle, cogeneration plant located in Bartow, Florida and a 50 percent
interest in Orange, a 103-megawatt, gas-fired, combined cycle, cogeneration
plant located in Bartow, Florida. 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
indicative bids, it was determined that an other than temporary impairment
existed on the two equity method investments located in Colorado. The $70.0
million pre-tax ($45.5 million, net of tax) impairment recorded in September
2003 was the result of the measurement of fair value that was triggered by our
recent decision to sell the assets. This loss of investment value was included
in Investment Value Losses on our Consolidated Statements of Operations for the
year ended December 31, 2003.
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 to Other Income (Expense), Net) 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 Federal Energy Regulatory
Commission approval and is expected to close during the third quarter 2004, with
no significant effect on results of operations during the third quarter.
U.K. Generation (Investments - UK Operations segment)
- -----------------------------------------------------
In December 2001, we acquired two coal-fired generation plants (U.K. Generation)
in the U.K. for a cash payment of $942.3 million and assumption of certain
liabilities. Since December 2001, we also made additional equity contributions
to fund our UK Operations. Subsequently and continuing through 2002, wholesale
U.K. electric power prices declined sharply as a result of domestic
over-capacity and static demand. External industry forecasts and our own
projections made during the fourth quarter of 2002 indicated that this situation
may extend many years into the future. As a result, the U.K. Generation fixed
asset carrying value at year-end 2002 was substantially impaired. A December
2002, probability-weighted discounted cash flow analysis of the fair value of
our U.K. Generation indicated a 2002 pre-tax impairment loss of $548.7 million
($414 million after-tax). This impairment loss is included in 2002 Discontinued
Operations on our Consolidated Statements of Operations.
In the fourth quarter of 2003, the U.K. generation plants were determined to be
non-core assets and management engaged an investment advisor to assist in
determining the best methodology to exit the U.K. business. An information
memorandum was distributed for the sale of our U.K. generation plants. Based on
information received, we recorded a $577 million pre-tax charge ($375
after-tax), including asset impairments of $420.7 million during the fourth
quarter of 2003 to write down the value of the assets to their estimated
realizable value. Additional charges of $156.7 million pre-tax were also
recorded in December 2003 including $122.2 million related to the net loss on
certain cash flow hedges previously recorded in Accumulated Other Comprehensive
Income (Loss) that have been reclassified into earnings as a result of
management's determination that the hedged event is no longer probable of
occurring and $34.5 million related to a first quarter 2004 sale of certain
power contracts. The assets and liabilities of U.K. Generation have been
classified as held for sale on our Consolidated Balance Sheets and the results
of operations are included in Discontinued Operations on our Consolidated
Statements of Operations.
In July 2004, we completed the sale of substantially all operations and assets
within the U.K. The sale included our two coal-fired generation plants
(Fiddler's Ferry and Ferrybridge) that were held-for-sale as described above,
related coal assets, and a number of related commodities contracts for
approximately $456 million. We are still determining the final impact from the
sale on our third quarter 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.
Excess Real Estate (Investments - Other segment)
- ------------------------------------------------
In the fourth quarter of 2002, we began to market an under-utilized office
building in Dallas, TX obtained through our merger with CSW in June 2000. One
prospective buyer executed an option to purchase the building. Sale of the
facility was projected by second quarter 2003 and an estimated 2002 pre-tax loss
on disposal of $15.7 million was recorded, based on the option sale price. The
estimated loss was included in Asset Impairments on AEP's Consolidated
Statements of Operations in 2002. In December 2003, we recorded an additional
pre-tax impairment of $6 million recorded in Maintenance and Other Operation on
our Consolidated Statements of Operations. The original prospective buyer did
not complete their purchase of the building by the end of 2003, and thus, the
asset no longer qualified for held for sale status. The building was then
reclassified to held and used status as of December 31, 2003.
In June 2004, we entered into negotiations to sell the Dallas office building.
This resulted in the asset again being classified as held for sale in the second
quarter of 2004. An additional pre-tax impairment of $2.5 million was recorded
to Maintenance and Other Operation expense during the second quarter of 2004 to
write down the value of the office building to the current estimated sales
price, less estimated selling expenses. The property asset of $9.5 million at
June 30, 2004 and $12.0 million at December 31, 2003 has been classified on
AEP's Consolidated Balance Sheets as held for sale. Although the negotiations
entered into in June 2004 did not yield a final signed purchase agreement,
active efforts to sell the building continue and we do not expect the sale to
have a significant effect on our results of operations.
DISCONTINUED OPERATIONS
- -----------------------
Management periodically assesses the overall AEP business model and makes
decisions regarding our continued support and funding of our various businesses
and operations. When it is determined that we will seek to exit a particular
business or activity and we have met the accounting requirements for
reclassification, we will reclassify the operations of those businesses or
operations as discontinued operations. The assets and liabilities of these
discontinued operations are classified as Assets and Liabilities Held for Sale
until the time that they are sold. At the time they are sold they are
reclassified to Assets and Liabilities of Discontinued Operations on the
Consolidated Balance Sheets for all periods presented. Assets and liabilities
that are held for sale, but do not qualify as a discontinued operations are
reflected as Assets and Liabilities Held for Sale both while they are held for
sale and after they have been sold, for all periods presented.
Certain of our operations were determined to be discontinued operations and have
been classified as such for all periods presented. Results of operations of
these businesses have been reclassified for the three and six month periods
ended June 30, 2004 and 2003, as shown in the following table:
For the three months ended June 30, 2004 and 2003:
Pushan
Power U.K.
Eastex Plant LIG Generation Total
------ ------ --- ---------- -----
(in millions)
2004 Revenue $- $- $4 $34 $38
2004 Pretax Income (Loss) - - 2 (80) (78)
2004 Income (Loss) After-Tax - (1) 2 (52) (51)
2003 Revenue 15 12 150 61 238
2003 Pretax Income (Loss) (9) - 3 4 (2)
2003 Income (Loss) After-Tax (7) - 1 4 (2)
For the six months ended June 30, 2004 and 2003:
Pushan
Power U.K.
Eastex Plant LIG Generation Total
------ ------ --- ---------- -----
(in millions)
2004 Revenue $- $10 $164 $75 $249
2004 Pretax Income (Loss) - 9 1 (99) (89)
2004 Income (Loss) After-Tax - 5 1 (64) (58)
2003 Revenue 46 27 353 112 538
2003 Pretax Income (Loss) (23) - 6 (36) (53)
2003 Income (Loss) After-Tax (15) - 4 (37) (48)
Assets and liabilities of discontinued operations have been reclassified as follows:
Pushan Power LIG (excluding
Plant Jefferson Island) Total
------------ ----------------- -----
(in millions)
As of December 31, 2003
-----------------------
Current Assets $24 $49 $73
Property, Plant and Equipment, Net 142 109 251
Goodwill - 1 1
Other - 8 8
----- ----- -----
Total Assets of Discontinued Operations $166 $167 $333
===== ===== =====
Current Risk Management Liabilities $- $15 $15
Current Liabilities 26 42 68
Long-term Debt 20 - 20
Deferred Credits and Other 57 6 63
----- ----- -----
Total Liabilities of Discontinued Operations $103 $63 $166
===== ===== =====
Pushan Power Plant (Investments - Other segment)
- ------------------------------------------------
See Pushan Power Plant section under Dispositions Completed During First Quarter
2004 for information regarding the sale of Pushan Power Plant.
Louisiana Intrastate Gas (LIG) (Investments - Gas Operations segment)
- ---------------------------------------------------------------------
As a result of our 2003 decision to exit our non-core businesses, we actively
marketed LIG Pipeline Company (gas pipeline and processing operations) and
Jefferson Island Storage & Hub, L.L.C. (JISH) (gas storage) together as a
combined operation. For the year ended December 31, 2003, LIG's assets
(including those of JISH) were classified as held for sale and their operations
where shown under Discontinued Operations. In January 2004, a decision was made
to sell LIG's pipeline and processing assets separate from LIG's gas storage
assets. After receiving and analyzing initial bids during the fourth quarter of
2003, we recorded a $133.9 million pre-tax ($99 million after-tax) impairment
loss; of this loss, $128.9 million pre-tax relates to the impairment of goodwill
and $5 million pre-tax relates to other charges. In February 2004, we signed a
definitive agreement to sell LIG Pipeline Company, which owned all of the
pipeline and processing assets of LIG. The sale was completed in April 2004 and
the impact on results of operations in the second quarter of 2004 was not
significant (see LIG Pipeline Company and its Subsidiaries in Dispositions
Completed During Second Quarter 2004 for additional information). Management
continues its efforts to market JISH. The assets and liabilities of LIG (not
including JISH) are classified as Assets of Discontinued Operations and
Liabilities of Discontinued Operations on our Consolidated Balance Sheets and
the results of operations (including the above-mentioned impairments and other
related charges) are classified in Discontinued Operations in our Consolidated
Statements of Operations. The gas storage assets of JISH remain held for sale as
of June 30, 2004. It is anticipated that the sale of JISH will take place by the
end of the year, and that it will not have a significant impact on our results
of operation's.
U.K. Generation
- ---------------
See U.K. Generation section under Dispositions Completed or Scheduled to be
Completed During Second Half 2004 for information regarding the sale of U.K.
Generation assets in July 2004.
ASSETS HELD FOR SALE
- --------------------
The assets and liabilities of the entities held for sale at June 30, 2004 and
December 31, 2003 are as follows:
U.K. Texas Excess Real Jefferson
June 30, 2004 Generation Plants Estate Island Total
- ------------- ---------- ------ ----------- --------- -----
(in millions)
Assets:
- -------
Current Risk Management Assets $251 $- $- $- $251
Other Current Assets 372 58 - 3 433
Property, Plant and Equipment, Net 115 796 10 63 984
Regulatory Assets - 51 - - 51
Decommissioning Trusts - 132 - - 132
Goodwill - - - 14 14
Long-term Risk Management Assets 56 - - - 56
Other 117 - - 17 134
----- ------- ---- ---- -------
Total Assets Held for Sale $911 $1,037 $10 $97 $2,055
===== ======= ==== ==== =======
Liabilities:
- ------------
Current Risk Management Liabilities $276 $- $- $- $276
Other Current Liabilities 156 - - 2 158
Long-term Risk Management Liabilities 49 - - - 49
Regulatory Liabilities - 9 - - 9
Asset Retirement Obligations 45 227 - - 272
Employee Pension Obligations 10 - - - 10
Deferred Credits and Other 1 - - - 1
----- ------- ---- ---- -------
Total Liabilities Held for Sale $537 $236 $- $2 $775
===== ======= ==== ==== =======
AEP U.K. Texas Excess Real Jefferson
December 31, 2003 Coal Generation Plants Estate Island Total
- ----------------- ---- ---------- ------ ----------- --------- -----
(in millions)
Assets:
- -------
Current Risk Management Assets $- $560 $- $- $- $560
Other Current Assets 6 685 57 - 1 749
Property, Plant and Equipment, Net 13 99 797 12 62 983
Regulatory Assets - - 49 - - 49
Decommissioning Trusts - - 125 - - 125
Goodwill - - - - 14 14
Long-term Risk Management Assets - 274 - - - 274
Other - 6 - - 1 7
---- ------- ------- ---- ---- -------
Total Assets Held for Sale $19 $1,624 $1,028 $12 $78 $2,761
==== ======= ======= ==== ==== =======
Liabilities:
- ------------
Current Risk Management
Liabilities $- $767 $- $- $- $767
Other Current Liabilities - 221 - - 4 225
Long-term Risk Management
Liabilities - 435 - - - 435
Regulatory Liabilities - - 9 - - 9
Asset Retirement Obligations 11 29 219 - - 259
Employee Pension Obligations - 12 - - - 12
Deferred Credits and Other 3 - - - - 3
---- ------- ------- ---- ---- -------
Total Liabilities Held for Sale $14 $1,464 $228 $- $4 $1,710
==== ======= ======= ==== ==== =======
8. BENEFIT PLANS
-------------
Components of Net Periodic Benefit Costs
- ----------------------------------------
The following table provides the components of our net periodic benefit cost
(credit) for the following plans for the three and six months ended June 30,
2004 and 2003:
U.S.
U.S. Other Postretirement
Three Months ended June 30, 2004 and 2003: Pension Plans Benefit Plans
- ------------------------------------------ --------------------- -----------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Service Cost $21 $20 $10 $11
Interest Cost 57 59 30 33
Expected Return on Plan Assets (73) (80) (20) (17)
Amortization of Transition
(Asset) Obligation 1 (2) 7 6
Amortization of Net Actuarial Loss 4 3 9 13
----- ----- ---- ----
Net Periodic Benefit Cost $10 $- $36 $46
===== ===== ==== ====
U.S.
U.S. Other Postretirement
Six Months ended June 30, 2004 and 2003: Pension Plans Benefit Plans
- ---------------------------------------- --------------------- ----------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Service Cost $43 $40 $20 $21
Interest Cost 114 117 59 65
Expected Return on Plan Assets (146) (159) (41) (32)
Amortization of Transition
(Asset) Obligation 1 (4) 14 14
Amortization of Net Actuarial Loss 8 5 18 26
----- ----- ---- ----
Net Periodic Benefit Cost (Credit) $20 $(1) $70 $94
===== ===== ==== ====
In accordance with our implementation of FASB Staff Position FAS 106-2, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003," as discussed in Note 2, accounting for the Medicare
subsidy reduced expected 2004 postretirement benefit cost by $29 million. As a result, expected cash flows for 2004 employer
contributions to U.S. other postretirement benefit plans have been reduced by $29 million from the $180 million disclosed at
December 31, 2003. Including an additional $19 million reduction related to refining earlier estimates, we currently expect to
contribute approximately $132 million to our U.S. other postretirement benefit plans during 2004.
9. BUSINESS SEGMENTS
-----------------
Our segments and their related business activities are as follows:
Utility Operations
- ------------------
o Domestic generation of electricity for sale to retail and wholesale
customers
o Domestic electricity transmission and distribution
Investments - Gas Operations*
- -----------------------------
o Gas pipeline and storage services
Investments - UK Operations**
- -----------------------------
o International generation of electricity for sale to wholesale customers
o Coal procurement and transportation to AEP's U.K. plants
Investments - Other
- -------------------
o Bulk commodity barging operations, windfarms, independent power producers
and other energy supply businesses
* Operations of Louisiana Intrastate Gas were classified as discontinued during
2003.
** UK Operations were classified as discontinued during 2003.
The tables below present segment income statement information for the three and
six months ended June 30, 2004 and 2003 and balance sheet information as of June
30, 2004 and December 31, 2003. These amounts include certain estimates and
allocations where necessary. Prior year amounts have been reclassified to
conform to the current year's presentation.
Investments
---------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
(in millions)
Three Months Ended June 30, 2004
- --------------------------------
Revenues from:
External Customers $2,501 $777 $- $90 $- $- $3,368
Other Operating Segments 43 40 - 19 (2) (100) -
Total Revenues 2,544 817 - 109 (2) (100) 3,368
Income (Loss) Before
Discontinued Operations and
Cumulative Effect of
Accounting Changes 183 (4) - (3) (25) - 151
Discontinued Operations, Net
of Tax - 2 (52) (1) - - (51)
Net Income (Loss) 183 (2) (52) (4) (25) - 100
As of June 30, 2004
- -------------------
Total Assets $31,235 $2,207 $800 $1,519 $13,090 $(13,003) $35,848
Assets Held for Sale and
Assets of Discontinued
Operations 1,037 97 911 10 - - 2,055
* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
company subsidiary, which provides services at cost to the other operating segments.
Investments
---------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
(in millions)
Three Months Ended June 30, 2003
- --------------------------------
Revenues from:
External Customers $2,672 $638 $- $140 $- $- $3,450
Other Operating Segments (7) 37 - 28 4 (62) -
Total Revenues 2,665 675 - 168 4 (62) 3,450
Income (Loss) Before
Discontinued Operations
and Cumulative Effect of
Accounting Changes 225 (25) - (20) (3) - 177
Discontinued Operations,
Net of Tax - 1 4 (7) - - (2)
Net Income (Loss) 225 (24) 4 (27) (3) - 175
As of December 31, 2003
- -----------------------
Total Assets $30,816 $2,405 $1,705 $1,697 $14,925 $(14,804) $36,744
Assets Held for Sale and
Assets of Discontinued
Operations 1,028 245 1,624 185 12 - 3,094
* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
company subsidiary, which provides services at cost to the other operating segments.
Investments
---------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
(in millions)
Six Months Ended June 30, 2004
- ------------------------------
Revenues from:
External Customers $5,080 $1,429 $- $200 $- $- $6,709
Other Operating Segments 69 39 - 50 4 (162) -
Total Revenues 5,149 1,468 - 250 4 (162) 6,709
Income (Loss) Before
Discontinued Operations and
Cumulative Effect of
Accounting Changes 486 (13) - 1 (34) - 440
Discontinued Operations,
Net of Tax - 1 (64) 5 - - (58)
Net Income (Loss) 486 (12) (64) 6 (34) - 382
As of June 30, 2004
- -------------------
Total Assets $31,235 $2,207 $800 $1,519 $13,090 $(13,003) $35,848
Assets Held for Sale and
Assets of Discontinued
Operations 1,037 97 911 10 - - 2,055
* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
company subsidiary, which provides services at cost to the other operating segments.
Investments
---------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
(in millions)
Six Months Ended June 30, 2003
- ------------------------------
Revenues from:
External Customers $5,359 $1,571 $- $305 $- $- $7,235
Other Operating Segments 12 52 - 43 7 (114) -
Total Revenues 5,371 1,623 - 348 7 (114) 7,235
Income (Loss) Before
Discontinued Operations
and Cumulative Effect of
Accounting Changes 531 (43) - - (18) - 470
Discontinued Operations,
Net of Tax - 4 (37) (15) - - (48)
Cumulative Effect of
Accounting Changes,
Net of Tax 236 (22) (21) - - - 193
Net Income (Loss) 767 (61) (58) (15) (18) - 615
As of December 31, 2003
- -----------------------
Total Assets $30,816 $2,405 $1,705 $1,697 $14,925 $(14,804) $36,744
Assets Held for Sale and
Assets of Discontinued
Operations 1,028 245 1,624 185 12 - 3,094
* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service
company subsidiary, which provides services at cost to the other operating segments.
10. FINANCING ACTIVITIES
--------------------
Long-term debt and other securities issued and retired during the first six months of 2004 are shown in the table below.
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in millions) (%)
Issuances:
- ---------
CSPCo Installment Purchase Contracts $44 Variable 2038
OPCo Financing Obligation 6 5.77 2024
PSO Installment Purchase Contracts 34 Variable 2014
PSO Senior Unsecured Notes 50 4.70 2009
SWEPCo Installment Purchase Contracts 54 Variable 2019
SWEPCo Installment Purchase Contracts 41 Variable 2011
SWEPCo Financing Obligation 14 5.77 2024
Non-Registrant:
AEP Subsidiary Notes Payable 23 Variable 2009
AEP Subsidiaries Other Debt 2 Variable Various
-----
Total Issuances $268 (a)
=====
(a) Amount indicated on statement of cash flows of $263 million is net of issuance costs.
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in millions) (%)
Retirements:
- -----------
AEP Senior Unsecured Notes $57 5.25 2015
AEP Senior Unsecured Notes 10 5.375 2010
APCo First Mortgage Bonds 45 7.125 2024
APCo Installment Purchase Contracts 40 5.45 2019
CSPCo First Mortgage Bonds 11 7.60 2024
CSPCo Installment Purchase Contracts 44 6.25 2020
I&M First Mortgage Bonds 30 7.20 2024
I&M First Mortgage Bonds 25 7.50 2024
OPCo Installment Purchase Contracts 50 6.85 2022
OPCo Notes Payable 2 6.27 2009
OPCo Notes Payable 3 6.81 2008
OPCo First Mortgage Bonds 10 7.30 2024
OPCo Senior Unsecured Notes 140 7.375 2038
PSO Notes Payable to Trust 77 8.00 2037
PSO Installment Purchase Contracts 34 4.875 2014
SWEPCo Installment Purchase Contracts 12 6.90 2004
SWEPCo Installment Purchase Contracts 12 6.00 2008
SWEPCo Installment Purchase Contracts 17 8.20 2011
SWEPCo Installment Purchase Contracts 54 7.60 2019
SWEPCo First Mortgage Bonds 80 6.875 2025
SWEPCo First Mortgage Bonds 40 7.75 2004
SWEPCo Notes Payable 3 4.47 2011
SWEPCo Notes Payable 2 Variable 2008
TCC First Mortgage Bonds 6 6.625 2005
TCC Securitization Bonds 29 3.54 2005
TNC First Mortgage Bonds 24 6.125 2004
Non-Registrant:
AEP Subsidiaries Notes Payable 40 6.73 2004
AEP Subsidiaries Notes Payable and Other Debt 114 Variable 2007-2017
-------
Total Retirements $1,011 (b)
=======
(b) Amount indicated on statement of cash flows of $986 million does not include $25 million related to retirement of debt of a
discontinued operation.
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in millions) (%)
Defeasance:
- ----------
TCC First Mortgage Bonds $27 7.25 2004
TCC First Mortgage Bonds 66 6.625 2005
TCC First Mortgage Bonds 19 7.125 2008
-----
Total Defeased $112 (c)
=====
(c) Trust fund assets for defeasance of First Mortgage Bonds of $103 million are included in Other Cash Deposits and $22 million
in Other Non-current Assets in the Consolidated Balance Sheets at June 30, 2004. Trust fund assets are restricted for
exclusive use in retiring the First Mortgage Bonds.
AEP GENERATING COMPANY
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Operating revenues are derived from the sale of Rockport Plant energy and
capacity to I&M and KPCo pursuant to FERC approved long-term unit power
agreements. The unit power agreements provide for a FERC approved rate of return
on common equity, a return on other capital (net of temporary cash investments)
and recovery of costs including operation and maintenance, fuel and taxes.
Net Income decreased $262 thousand for the second quarter of 2004 compared with
the second quarter of 2003 and decreased $231 thousand for the six months ended
June 30, 2004 compared with the six months ended June 30, 2003. The fluctuations
in Net Income are a result of terms in the unit power agreements which allow for
the return on total capital of the Rockport Plant calculated and adjusted
monthly.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $141 thousand for the second quarter of 2004 compared
with the second quarter of 2003. The largest variances related to:
o A $3 million decrease in Operating Revenue as a result of decreased
recoverable expenses in accordance with the unit power agreements.
o A $4 million decrease in Fuel for Electric Generation expense. This
decrease is primarily due to a 16% decrease in MWH generation as a
result of both planned and forced outages.
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were (19.7)% and
(5.8)%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, amortization of investment tax credits and state income taxes. The
decrease in the effective tax rate is primarily due to lower pre-tax income in
2004, flow-through differences, and state income taxes.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $445 thousand for the six months ended June 30, 2004
compared with the six months ended June 30, 2003. The largest variances related
to:
o An $8 million decrease in Operating Revenue as a result of decreased
recoverable expenses in accordance with the unit power agreements.
o A $4 million increase in Maintenance expense as a result of increased
planned boiler inspections and forced repairs.
o A $13 million decrease in Fuel for Electric Generation expense. This
decrease is primarily due to a 23% decrease in MWH generation as a result
of both planned and forced outages.
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were (13.9)%
and (16.1)%, 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, amortization of investment tax credits and state income taxes. The
increase in the effective tax rate is primarily due to higher flow-through
differences and state income taxes offset by lower pre-tax income in 2004.
Off-balance Sheet Arrangements
- ------------------------------
In prior years, we entered into off-balance sheet arrangements. Our off-balance
sheet arrangement has not changed significantly from year-end 2003 and is
comprised of a sale and leaseback transaction entered into by AEGCo and I&M with
an unrelated unconsolidated trustee. Our current policy restricts the use of
off-balance sheet financing entities or structures, except for traditional
operating lease arrangements. For complete information on this off-balance
sheet arrangement see "Off-balance Sheet Arrangements" in "Management's
Narrative Financial Discussion and Analysis" section of our 2003 Annual Report.
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets and the impact of new accounting pronouncements.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
------------------------ ------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $56,348 $59,568 $111,630 $119,996
-------- -------- --------- ---------
OPERATING EXPENSES
- ------------------------------------------
Fuel for Electric Generation 25,036 29,237 46,434 59,634
Rent - Rockport Plant Unit 2 17,071 17,071 34,142 34,142
Other Operation 2,665 2,442 5,155 4,991
Maintenance 2,790 2,287 8,190 3,938
Depreciation and Amortization 5,772 5,665 11,506 11,286
Taxes Other Than Income Taxes 942 604 1,886 1,395
Income Taxes 699 748 1,397 1,245
-------- -------- --------- ---------
TOTAL 54,975 58,054 108,710 116,631
-------- -------- --------- ---------
OPERATING INCOME 1,373 1,514 2,920 3,365
Nonoperating Income 5 19 29 21
Nonoperating Expenses 80 25 149 242
Nonoperating Income Tax Credits 947 845 1,804 1,739
Interest Charges 739 585 1,271 1,319
-------- -------- --------- ---------
NET INCOME $1,506 $1,768 $3,333 $3,564
======== ======== ========= =========
STATEMENTS OF RETAINED EARNINGS
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
------------------------ ------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $22,006 $18,788 $21,441 $18,163
Net Income 1,506 1,768 3,333 3,564
Cash Dividends Declared 1,261 1,172 2,523 2,343
-------- -------- -------- --------
BALANCE AT END OF PERIOD $22,251 $19,384 $22,251 $19,384
======== ======== ======== ========
The common stock of AEGCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ----------------------------------------------
Production $667,819 $645,251
General 4,039 4,063
Construction Work in Progress 5,419 24,741
--------- ---------
TOTAL 677,277 674,055
Accumulated Depreciation 355,855 351,062
--------- ---------
TOTAL - NET 321,422 322,993
--------- ---------
OTHER PROPERTY AND INVESTMENTS
- ----------------------------------------------
Non-Utility Property, Net 119 119
--------- ---------
CURRENT ASSETS
- ----------------------------------------------
Accounts Receivable - Affiliated Companies 23,996 24,748
Fuel 24,061 20,139
Materials and Supplies 5,508 5,419
Prepayments 21 -
--------- ---------
TOTAL 53,586 50,306
--------- ---------
DEFERRED DEBITS AND OTHER ASSETS
- ----------------------------------------------
Regulatory Assets:
Unamortized Loss on Reacquired Debt 4,614 4,733
Asset Retirement Obligations 1,022 928
Deferred Property Taxes 2,134 502
Other Deferred Charges 436 464
--------- ---------
TOTAL 8,206 6,627
--------- ---------
TOTAL ASSETS $383,333 $380,045
========= =========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- -----------------------------------------------------
Common Shareholder's Equity:
Common Stock - Par Value $1,000 per share:
Authorized and Outstanding - 1,000 Shares $1,000 $1,000
Paid-in Capital 23,434 23,434
Retained Earnings 22,251 21,441
--------- ---------
Total Common Shareholder's Equity 46,685 45,875
Long-term Debt 44,815 44,811
--------- ---------
TOTAL 91,500 90,686
--------- ---------
CURRENT LIABILITIES
- -----------------------------------------------------
Advances from Affiliates 42,758 36,892
Accounts Payable:
General 897 498
Affiliated Companies 13,286 15,911
Taxes Accrued 10,527 6,070
Interest Accrued 911 911
Obligations Under Capital Leases 69 87
Rent Accrued - Rockport Plant Unit 2 4,963 4,963
Other 98 -
--------- ---------
TOTAL 73,509 65,332
--------- ---------
DEFERRED CREDITS AND OTHER LIABILITIES
- -----------------------------------------------------
Deferred Income Taxes 23,983 24,329
Regulatory Liabilities:
Asset Removal Costs 27,863 27,822
Deferred Investment Tax Credits 47,921 49,589
SFAS 109 Regulatory Liability, Net 14,531 15,505
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 102,690 105,475
Obligations Under Capital Leases 166 182
Asset Retirement Obligations 1,170 1,125
--------- ---------
TOTAL 218,324 224,027
--------- ---------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $383,333 $380,045
========= =========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- --------------------------------------------------------
Net Income $3,333 $3,564
Adjustments to Reconcile Net Income to Net Cash Flows From
Operating Activities:
Depreciation and Amortization 11,506 11,286
Deferred Income Taxes (1,319) (2,158)
Deferred Investment Tax Credits (1,668) (1,668)
Deferred Property Taxes (1,632) (1,573)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (2,785) (2,785)
Changes in Certain Assets and Liabilities:
Accounts Receivable 752 (4,174)
Fuel, Materials and Supplies (4,011) 4,213
Accounts Payable (2,226) (2,939)
Taxes Accrued 4,457 3,806
Change in Other Assets (93) (751)
Change in Other Liabilities 154 884
------- -------
Net Cash Flows From Operating Activities 6,468 7,705
------- -------
INVESTING ACTIVITIES
- --------------------------------------------------------
Construction Expenditures (9,811) (4,012)
------- -------
Net Cash Flows Used For Investing Activities (9,811) (4,012)
------- -------
FINANCING ACTIVITIES
- --------------------------------------------------------
Change in Advances from Affiliates 5,866 (1,350)
Dividends Paid (2,523) (2,343)
------- -------
Net Cash Flows From (Used For) Financing Activities 3,343 (3,693)
------- -------
Net Decrease in Cash and Cash Equivalents - -
Cash and Cash Equivalents at Beginning of Period - -
------- -------
Cash and Cash Equivalents at End of Period $- $-
======= =======
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $1,138,000 and $1,186,000 and for income taxes was $570,000 and $2,448,000
in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP GENERATING COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to AEGCo's financial statements are combined with the notes to
financial statements for other subsidiary registrants. Listed below are the
notes that apply to AEGCo. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Commitments and Contingencies Note 5
Guarantees Note 6
Business Segments Note 9
Financing Activities Note 10
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income decreased $99 million for 2004 year-to-date, and $64 million for the
second quarter. The three major factors driving the decline for both periods
are; the decreased revenues associated with establishing regulatory assets in
Texas, the provision for refunds of fuel charges, and the decrease in retail
delivery revenue due mainly to milder weather. These items accounted for a $99
million decrease year-to-date and a $70 million decrease for the quarter. The
cessation of depreciation on plants held for sale partially offset these
declines.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $73 million primarily due to:
o Decreased revenues associated with establishing regulatory assets in
Texas of $52 million in 2003 (see "Texas Restructuring" in Note 4). These
revenues did not continue after 2003.
o Increased provisions for rate refunds of $37 million due to fuel
reconciliation issues (see "TCC Fuel Reconciliation" in Note 3).
o Decreased retail delivery revenues of $19 million driven primarily by a
decrease in cooling degree-days of 23%.
o Decreased system sales, including those to REPs, of $88 million due mainly
to lower KWH sales of 36% due to customer choice in Texas and a small
decrease in the overall average price per KWH.
o Decreased Reliability Must Run (RMR) revenues from ERCOT of $4 million,
which includes both a fixed cost component decrease of $8 million and fuel
recovery increase of $4 million.
o Decreased Qualified Scheduling Entity (QSE) fees of $3 million due mainly to
one REP not using TCC as their QSE in 2004.
o Decreased margins of $16 million resulting from risk management activities.
o Increased Other Operation expenses of $10 million due mainly to $3 million
increase of ERCOT-related transmission expense and affiliated ancillary
services; $2 million higher customer related expenses; increased emission
allowance expense and administrative and support expense of $3 million.
o Increased Taxes Other than Income Taxes of $3 million mainly due to
increased property taxes.
The decrease in Operating Income was partially offset by:
o Net decreases in fuel and purchased electricity on a combined basis of $91
million. KWH's purchased decreased 86% while the per unit cost increased 1%.
Although the KWH generated increased 16%, generating costs increased 22%
attributable mostly to higher prices for natural gas offset in part by both
units of STP being on line in 2004 whereas in 2003 only one unit was
operating.
o Increased revenues from ERCOT of $10 million for various services, including
balancing energy.
o Increased transmission revenue of $1 million due mainly to affiliated OATT
and ancillary services.
o Decreased Depreciation and Amortization expense of $25 million due mainly
to the cessation of depreciation on Texas plants classified as "Held For
Sale."
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $4 million primarily as a result of increased
income of $8 million related to risk management activities offset in part by $4
million lower non-utility revenues associated with energy-related construction
projects for third parties.
Nonoperating Expense decreased $3 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties
offset in part by an increase in donations.
Interest charges decreased $3 million primarily due to the defeasance of $112
million of First Mortgage Bonds and the deferral of the interest cost as a cost
of the sale of generation assets as well as other financing activities.
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were 94.2% and
33.6%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The increase in the effective tax
rate is primarily due to pre-tax income becoming a loss in 2004 and lower state
income taxes.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $110 million primarily due to:
o Decreased revenues associated with establishing regulatory assets in
Texas of $108 million in 2003 (see "Texas Restructuring" in Note 4).
These revenues did not continue after 2003.
o Increased provisions for rate refunds of $23 million due to fuel
reconciliation issues (see "TCC Fuel Reconciliation" in Note 3).
o Decreased system sales, including those to REPs, of $165 million due
mainly to lower KWH sales of 33% due to customer choice in Texas and a
small decrease in the overall average price per KWH.
o Decreased revenues from ERCOT of $4 million for various services, including
balancing energy.
o Decreased retail delivery revenues of $22 million driven by a decrease of
KWH of 3% due in large part to a decrease in cooling degree-days of 16%.
o Decreased RMR revenues from ERCOT of $9 million, which includes both a
fuel recovery decrease of $7 million and a fixed cost component decrease
of $2 million.
o Decreased QSE fees of $8 million due mainly to one REP not using TCC as
their QSE in 2004.
o Decreased margins from risk management activities of $15 million.
o Increased Other Operation expenses of $18 million due mainly to $8 million
increase of ERCOT-related transmission expense and affiliated ancillary
services; $2 million increase of production expense including emission
allowances; $2 million increase in customer related expense; and an
increase of $4 million of administrative and support expense.
The decrease in Operating Income was partially offset by:
o Net decreases in fuel and purchased electricity on a combined basis of
$163 million. KWH purchased decreased 87% while the per unit cost
increased 8%. The KWH generated increased 19% and per unit costs decreased
8% attributable mostly to the fact that both units of STP were on line in
2004.
o Increased transmission revenue of $11 million due mainly to affiliated OATT
(including a $7.6 million 2004 true-up) and ancillary services.
o Decreased Depreciation and Amortization expense of $42 million due mainly
to the cessation of depreciation on Texas plants classified as "Held For
Sale."
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $6 million primarily as a result of increased
income of $9 million related to risk management activities offset in part by $5
million lower non-utility revenues associated with energy-related construction
projects for third parties.
Nonoperating Expense decreased $3 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties
offset in part by an increase in donations.
Interest charges decreased $2 million primarily due to the defeasance of $112
million of First Mortgage Bonds and the deferral of the interest cost as a cost
of the sale of generation assets as well as other financing activities.
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were 18.2% and
34.4%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower pre-tax income in 2004 and lower state income
taxes.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Our current ratings are
as follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds Baa1 BBB A
Senior Unsecured Debt Baa2 BBB A-
Cash Flow
- ---------
Cash flows for the six months ended June 30, 2004 and 2003 were as follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $760 $807
-------- ---------
Cash flow from (used for):
Operating activities 118,414 186,201
Investing activities (163,279) (23,912)
Financing activities 49,915 (162,937)
-------- ---------
Net increase (decrease) in cash and cash equivalents 5,050 (648)
-------- ---------
Cash and cash equivalents at end of period $5,810 $159
======== =========
Operating Activities
- --------------------
Cash Flows From Operating Activities in 2004 were $118 million primarily due to
Net Income, as explained above, Taxes Accrued, Accounts Payable and Changes in
Other Liabilities offset in part by Deferred Property Tax and Accounts
Receivable, Net.
Investing Activities
- --------------------
Investing expenditures in 2004 were $163 million due primarily to $49 million in
construction expenditures focused on improved service reliability projects for
transmission and distribution systems, and $117 million in cash deposits for
future long-term debt retirement.
Financing Activities
- --------------------
Cash used for financing activities in 2004 reduced Long-term Debt, paid
dividends and was offset by Advances to Affiliates.
Financing Activity
- ------------------
Long-term debt issuances, retirements and defeasance during the first six months
of 2004 were:
Issuances
---------
None
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $ 6,195 6.625 2005
Securitization Bonds 28,809 3.540 2005
Defeasance
----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $27,400 7.25 2004
First Mortgage Bonds 65,763 6.625 2005
First Mortgage Bonds 18,581 7.125 2008
Significant Factors
- -------------------
We made progress on our planned divestiture of all our generation assets by (1)
announcing in January 2004 that we had signed an agreement to sell our 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 our 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 our remaining generation assets, including eight natural gas plants,
one coal-fired plant and one hydro plant for approximately $425 million, net of
closing adjustments. Subject to certain issues that have arisen relating to
co-owners' rights of first refusal, we expect the sales of our share of
Oklaunion and South Texas Project to close before the end of 2004. There could,
however, be potential delays in receiving appropriate regulatory approvals and
clearances which may delay the closing. The sale of our remaining generation
assets was completed in July 2004. We will file with the Public Utility
Commission of Texas to recover net stranded costs associated with the sales
pursuant to Texas restructuring legislation.
Nuclear Decommissioning
- -----------------------
As discussed in the 2003 Annual Report, decommissioning costs are accrued over
the service life of STP. The licenses to operate the two nuclear units at STP
expire in 2027 and 2028. TCC had estimated its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of approximately $8 million per year.
In May 2004, an updated decommissioning study was completed for STP. The study
estimates TCC's share of the decommissioning costs of STP to be $344 million in
nondiscounted 2004 dollars. TCC is in the process of selling its ownership
interest in STP to a non-affiliate, and upon completion of the sale it is
anticipated that TCC will no longer be obligated for nuclear decommissioning
liabilities associated with STP.
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion on factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.
MTM Risk Management Contract Net Liabilities
- --------------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Liabilities
Six Months Ended June 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $11,942
(Gain) Loss from Contracts Realized/Settled During the Period (a) (2,867)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 45
Change in Fair Value Due to Valuation Methodology Changes (d) 110
Changes in Fair Value of Risk Management Contracts (e) (1,881)
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f) -
---------
Total MTM Risk Management Contract Net Assets 7,349
Net Cash Flow Hedge Contracts (g) (15,162)
---------
Total MTM Risk Management Contract Net Liabilities at June 30, 2004 $(7,813)
=========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and
unexpired option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Operations. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
Prices Actively Quoted - Exchange
Traded Contracts $(277) $27 $(1) $88 $- $- $(163)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (913) 580 115 - - - (218)
Prices Based on Models and Other
Valuation Methods (b) 6,481 451 (33) 87 187 557 7,730
------- ------- ---- ----- ----- ----- -------
Total $5,291 $1,058 $81 $175 $187 $557 $7,349
======= ======= ==== ===== ===== ===== =======
(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over-the-counter brokers, industry services, or
multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources, modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $(1,828)
Changes in Fair Value (a) (8,941)
Reclassifications from AOCI to Net
Income (b) (473)
---------
Ending Balance June 30, 2004 $(11,242)
=========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $11,145 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Management Contracts
- ----------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
---------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$71 $161 $80 $40 $189 $733 $307 $73
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $189 million and $206 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
---------------------- ---------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ----------------------------------------------------
Electric Generation, Transmission and Distribution $256,964 $439,049 $525,822 $821,179
Sales to AEP Affiliates 12,896 43,397 31,026 89,625
--------- --------- --------- ---------
TOTAL 269,860 482,446 556,848 910,804
--------- --------- --------- ---------
OPERATING EXPENSES
- ----------------------------------------------------
Fuel for Electric Generation 20,806 21,430 43,912 48,769
Fuel from Affiliates for Electric Generation 59,977 44,911 100,176 83,200
Purchased Electricity for Resale 16,468 116,654 26,554 188,776
Purchased Electricity from AEP Affiliates 1,938 7,210 6,011 18,772
Other Operation 77,977 68,283 153,418 135,678
Maintenance 23,709 21,811 39,113 37,910
Depreciation and Amortization 28,879 53,867 57,976 99,947
Taxes Other Than Income Taxes 23,157 19,783 45,214 42,762
Income Taxes (Credits) (6,388) 31,894 5,618 66,377
--------- --------- --------- ---------
TOTAL 246,523 385,843 477,992 722,191
--------- --------- --------- ---------
OPERATING INCOME 23,337 96,603 78,856 188,613
Nonoperating Income 12,061 7,901 24,163 18,063
Nonoperating Expenses 2,648 5,637 7,756 10,832
Nonoperating Income Tax Expense 880 240 860 798
Interest Charges 32,211 35,040 65,340 67,022
--------- --------- --------- ---------
Income (Loss) Before Cumulative Effect of Accounting Change (341) 63,587 29,063 128,024
Cumulative Effect of Accounting Change (Net of Tax) - - - 122
--------- --------- --------- ---------
NET INCOME (LOSS) (341) 63,587 29,063 128,146
Preferred Stock Dividend Requirements 61 61 121 121
--------- --------- --------- ---------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $(402) $63,526 $28,942 $128,025
========= ========= ========= =========
The common stock of TCC is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $55,292 $132,606 $986,396 $(73,160) $1,101,134
Common Stock Dividends (60,401) (60,401)
Preferred Stock Dividends (121) (121)
-----------
TOTAL 1,040,612
-----------
COMPREHENSIVE INCOME
- ----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (747) (747)
NET INCOME 128,146 128,146
-----------
TOTAL COMPREHENSIVE INCOME 127,399
-------- --------- ----------- --------- -----------
JUNE 30, 2003 $55,292 $132,606 $1,054,020 $(73,907) $1,168,011
======== ========= =========== ========= ===========
DECEMBER 31, 2003 $55,292 $132,606 $1,083,023 $(61,872) $1,209,049
Common Stock Dividends (48,000) (48,000)
Preferred Stock Dividends (121) (121)
-----------
TOTAL 1,160,928
-----------
COMPREHENSIVE INCOME
- ----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (9,414) (9,414)
Minimum Pension Liability (2,466) (2,466)
NET INCOME 29,063 29,063
-----------
TOTAL COMPREHENSIVE INCOME 17,183
-------- --------- ----------- --------- -----------
JUNE 30, 2004 $55,292 $132,606 $1,063,965 $(73,752) $1,178,111
======== ========= =========== ========= ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ------------------------------------------------------
Production $- $-
Transmission 776,784 767,970
Distribution 1,402,159 1,376,761
General 225,610 221,354
Construction Work in Progress 51,586 58,953
----------- -----------
TOTAL 2,456,139 2,425,038
Accumulated Depreciation and Amortization 713,376 695,359
----------- -----------
TOTAL - NET 1,742,763 1,729,679
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ------------------------------------------------------
Non-Utility Property, Net 1,340 1,302
Bond Defeasance Funds 21,773 -
Other Investments - 4,639
----------- -----------
TOTAL 23,113 5,941
----------- -----------
CURRENT ASSETS
- ------------------------------------------------------
Cash and Cash Equivalents 5,810 760
Other Cash Deposits 158,729 65,122
Advances to Affiliates - 60,699
Accounts Receivable:
Customers 189,128 146,630
Affiliated Companies 64,321 78,484
Accrued Unbilled Revenues 21,920 23,077
Allowance for Uncollectible Accounts (2,306) (1,710)
Materials and Supplies 13,705 11,708
Risk Management Assets 13,636 22,051
Margin Deposits 245 3,230
Prepayments and Other Current Assets 10,119 6,770
----------- -----------
TOTAL 475,307 416,821
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 3,100 3,249
Wholesale Capacity Auction True-up 480,000 480,000
Unamortized Loss on Reacquired Debt 8,606 9,086
Designated for Securitization 1,262,049 1,253,289
Deferred Debt - Restructuring 11,937 12,015
Other 123,090 133,913
Securitized Transition Assets 669,942 689,399
Long-term Risk Management Assets 2,797 7,627
Deferred Charges 71,248 55,554
----------- -----------
TOTAL 2,632,769 2,644,132
----------- -----------
Assets Held for Sale - Texas Generation Plants 1,037,138 1,028,134
----------- -----------
TOTAL ASSETS $5,911,090 $5,824,707
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ---------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 2,211,678 Shares $55,292 $55,292
Paid-in Capital 132,606 132,606
Retained Earnings 1,063,965 1,083,023
Accumulated Other Comprehensive Income (Loss) (73,752) (61,872)
----------- -----------
Total Common Shareholder's Equity 1,178,111 1,209,049
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,940 5,940
----------- -----------
Total Shareholder's Equity 1,184,051 1,214,989
Long-term Debt 1,627,705 2,053,974
----------- -----------
TOTAL 2,811,756 3,268,963
----------- -----------
CURRENT LIABILITIES
- ---------------------------------------------------------------
Long-term Debt Due Within One Year 629,118 237,651
Advances From Affiliates 72,341 -
Accounts Payable:
General 97,642 90,004
Affiliated Companies 84,952 74,209
Customer Deposits 5,878 1,517
Taxes Accrued 98,396 67,018
Interest Accrued 42,440 43,196
Risk Management Liabilities 22,657 17,888
Obligation Under Capital Leases 420 407
Other 20,063 23,248
----------- -----------
TOTAL 1,073,907 555,138
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ---------------------------------------------------------------
Deferred Income Taxes 1,233,508 1,244,912
Long-term Risk Management Liabilities 1,589 2,660
Regulatory Liabilities:
Asset Removal Costs 99,900 95,415
Deferred Investment Tax Credits 109,875 112,479
Deferred Fuel Costs 69,026 69,026
Retail Clawback 29,824 45,527
Other 44,812 56,984
Obligation Under Capital Leases 563 636
Deferred Credits and Other 200,028 144,833
----------- -----------
TOTAL 1,789,125 1,772,472
----------- -----------
Liabilities Held for Sale - Texas Generation Plants 236,302 228,134
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $5,911,090 $5,824,707
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- -----------------------------------------------------------
Net Income $29,063 $128,146
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change - (122)
Depreciation and Amortization 57,976 99,947
Deferred Income Taxes (11,682) 13,369
Deferred Investment Tax Credits (2,603) (2,603)
Deferred Property Taxes (22,440) (20,100)
Mark-to-Market of Risk Management Contracts 4,593 1,955
Wholesale Capacity Auction True-up - (108,400)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (26,582) (87,691)
Fuel, Materials and Supplies (3,735) 16,456
Accounts Payable 18,381 83,970
Taxes Accrued 31,378 48,277
Interest Accrued (756) (7,610)
Change in Other Assets 3,094 9,644
Change in Other Liabilities 41,727 10,963
--------- ---------
Net Cash Flows From Operating Activities 118,414 186,201
--------- ---------
INVESTING ACTIVITIES
- -----------------------------------------------------------
Construction Expenditures (49,311) (56,013)
Change in Other Cash Deposits, Net (93,607) 32,101
Change in Bond Defeasance Funds and Other (20,361) -
--------- ---------
Net Cash Flows Used For Investing Activities (163,279) (23,912)
--------- ---------
FINANCING ACTIVITIES
- -----------------------------------------------------------
Change in Short-term Debt - Affiliates - (650,000)
Issuance of Long-term Debt - 792,027
Retirement of Long-term Debt (35,004) (66,230)
Change in Advances to Affiliates 133,040 (178,212)
Dividends Paid on Common Stock (48,000) (60,401)
Dividends Paid on Cumulative Preferred Stock (121) (121)
--------- ---------
Net Cash Flows From (Used For) Financing Activities 49,915 (162,937)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 5,050 (648)
Cash and Cash Equivalents at Beginning of Period 760 807
--------- ---------
Cash and Cash Equivalents at End of Period $5,810 $159
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $61,529,000 and $72,918,000 and for income taxes was $(7,067,000)
and $7,803,000 in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to TCC's consolidated financial statements are combined with the notes
to financial statements for other subsidiary registrants. Listed below are the
notes that apply to TCC. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Dispositions and Assets Held for Sale Note 7
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
AEP TEXAS NORTH COMPANY
AEP TEXAS NORTH COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Net Income decreased $7 million for 2004 year-to-date, and $10 million for the
second quarter. The year-to-date decrease was driven by lower margins from risk
management activities and lower retail delivery revenues in Texas. These same
items drive the quarterly decline along with a provision for rate refunds from
fuel reconciliation proceedings.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income decreased by $12 million primarily due to:
o Increased provision for rate refunds of $13 million due to fuel
reconciliation issues (see "TNC Fuel Reconciliation" in Note 3).
o Decreased margins from risk management activities of $8 million.
o Decreased retail delivery revenues of $3 million due partly to a 13% decline
in cooling degree-days.
o Decreased system sales, including those to REPs, of $16 million due mainly
to both lower KWH sales of 17% and a small decrease in the overall average
price per KWH sold.
o Decrease of Reliability Must Run (RMR) revenues from ERCOT of $1 million
which include both fuel recovery and a fixed cost component.
o Increased Taxes Other than Income Taxes of $2 million resulting mainly from
higher accrued property taxes.
The decrease in Operating Income was partially offset by:
o Decreased fuel and purchased power on a combined basis of $15 million. KWH
generation increased 16%, while the generation cost per KWH increased 4%
due primarily to increases in the price of natural gas. KWH purchased
declined 9%, and the average cost per KWH purchased decreased 37%.
o Revenues from ERCOT increased $4 million for various services, including
balancing energy, due mainly to prior years adjustments made by ERCOT
recorded in 2003.
o Increased wholesale revenues of $2 million due to higher fuel revenue, as
the pricing is linked to average fuel cost.
o Increased Transmission revenue of $1 million, due mainly to affiliated
ancillary services.
o Decreased Other Operation expenses of $3 million, primarily due to proceeds
of $1 million for the sale of emission allowances; decreased production
expense of approximately $2 million due to the elimination of the RMR
status for the San Angelo Power Station - Unit 1; and decreased employee
related expenses.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $2 million as a result of a $5 million decrease in
non-utility revenues associated with energy-related construction projects for
third parties, offset in part by an increase of $3 million related to risk
management activities.
Nonoperating Expense decreased $5 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties.
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were 32.6% and
35.4% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower pre-tax income in 2004 and lower state income
taxes.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income decreased by $5 million primarily due to:
o Decreased system sales, including those to REPs, of $44 million due mainly
to both lower KWH sales of 24% due to customer choice in Texas and a small
decrease in the overall average price per KWH.
o Decreased retail delivery revenues of $3 million due partly to an 11%
decline in cooling degree-days.
o Increased provision for rate refunds of $1 million due to fuel
reconciliation issues in 2003 (see "TNC Fuel Reconciliation" in Note 3).
o Decreased margins from risk management activities of $9 million.
o Decreased revenues from ERCOT of $1 million for various services, including
balancing energy, due mainly to prior year adjustments made by ERCOT and
recorded in 2003.
o Increased Taxes Other than Income Taxes of $1 million resulting mainly from
higher accrued property taxes.
The decrease in Operating Income was partially offset by:
o Decreased fuel and purchased power on a combined basis of $37 million. KWH
purchased declined 31%, and the average cost per KWH purchased decreased
34%. KWH generation increased 6%, while the generation cost per KWH
increased 8% due primarily to increases in the price of natural gas.
o Increased Transmission revenue of $8 million, due mainly to prior year
adjustments recorded in 2003 for affiliated OATT and ancillary services
resulting from revised data received from ERCOT for the years 2001-2003.
o Increase of RMR revenues from ERCOT of $4 million, which include both a fuel
recovery increase of $6 million and a fixed cost decrease of $2 million.
o Increased wholesale revenues of $1 million due to higher fuel revenue which
is linked to average fuel cost pricing.
o Decreased Other Operation expenses of $3 million, primarily due to proceeds
of $1 million for the sale of emission allowances, decreased production
expense of approximately $2 million due to the elimination of the RMR status
for the San Angelo Power Station - Unit 1, as well as decreased
employee-related expenses.
Other Impacts on Earnings
- -------------------------
Nonoperating Income decreased $2 million primarily as a result of a $5 million
decrease in non-utility revenue associated with energy-related construction
projects for third parties, offset in part by an increase of $3 million related
to risk management activities.
Nonoperating Expense decreased $6 million primarily due to lower non-utility
expenses associated with energy-related construction projects for third parties.
The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 in 2003.
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were 33.7% and
37.1% respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to lower pre-tax income in 2004 and lower state income
taxes.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Our current ratings are
as follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 BBB A
Senior Unsecured Debt Baa1 BBB A-
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first six months of 2004
were:
Issuances
---------
None.
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $24,036 6.125 2004
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effects.
MTM Risk Management Contract Net Liabilities
- --------------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Liabilities
Six Months Ended June 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $4,620
(Gain) Loss from Contracts Realized/Settled During the Period (a) (982)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 20
Change in Fair Value Due to Valuation Methodology Changes (d) 45
Changes in Fair Value of Risk Management Contracts (e) (1,038)
Changes in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions (f) -
--------
Total MTM Risk Management Contract Net Assets 2,665
Net Cash Flow Hedge Contracts (g) (5,083)
--------
Total MTM Risk Management Contract Net Liabilities at June 30, 2004 $(2,418)
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and
unexpired option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changing methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Statements of Income. These
net gains (losses) are recorded as regulatory liabilities/assets
for those subsidiaries that operate in regulated jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
Prices Actually Quoted - Exchange Traded
Contracts $(111) $11 $- $35 $- $- $(65)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (231) 233 46 - - - 48
Prices Based on Models and Other
Valuation Methods (b) 2,180 181 (13) 35 75 224 2,682
------- ----- ---- ---- ---- ----- -------
Total $1,838 $425 $33 $70 $75 $224 $2,665
======= ===== ==== ==== ==== ===== =======
(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over- the-counter brokers, industry services, or
multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources, modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as
modeled. The determination of the point at which a market is no longer
liquid for placing it in the modeled category varies by market.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $(601)
Changes in Fair Value (a) (3,001)
Reclassifications from AOCI to Net
Income (b) (163)
--------
Ending Balance June 30, 2004 $(3,765)
========
(a)"Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b)"Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $3,727 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
---------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$29 $65 $32 $16 $76 $294 $123 $29
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $31 million and $33 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore, a near term change in interest rates should
not negatively affect our results of operation or financial position.
AEP TEXAS NORTH COMPANY
STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
--------------------- ---------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- -----------------------------------------------------------
Electric Generation, Transmission and Distribution $88,968 $120,568 $177,680 $216,629
Sales to AEP Affiliates 12,027 16,238 26,745 36,439
-------- -------- -------- --------
TOTAL 100,995 136,806 204,425 253,068
-------- -------- -------- --------
OPERATING EXPENSES
- -----------------------------------------------------------
Fuel for Electric Generation 10,661 8,278 18,161 19,739
Fuel from Affiliates for Electric Generation 12,542 10,917 23,766 17,002
Purchased Electricity for Resale 23,282 26,723 41,305 51,501
Purchased Electricity from AEP Affiliates 544 16,449 4,076 35,794
Other Operation 19,556 22,365 39,937 42,984
Maintenance 5,950 6,012 10,633 10,153
Depreciation and Amortization 9,854 9,723 19,546 19,255
Taxes Other Than Income Taxes 5,293 3,432 10,397 9,465
Income Taxes 2,541 9,664 8,482 14,067
-------- -------- -------- --------
TOTAL 90,223 113,563 176,303 219,960
-------- -------- -------- --------
OPERATING INCOME 10,772 23,243 28,122 33,108
Nonoperating Income 15,632 17,834 29,388 31,305
Nonoperating Expenses 11,962 17,114 22,898 28,681
Nonoperating Income Tax Expense 1,209 142 2,103 481
Interest Charges 5,482 5,899 11,662 10,564
-------- -------- -------- --------
Income Before Cumulative Effect of Accounting Changes 7,751 17,922 20,847 24,687
Cumulative Effect of Accounting Changes (Net of Tax) - - - 3,071
-------- -------- -------- --------
NET INCOME 7,751 17,922 20,847 27,758
Preferred Stock Dividend Requirements 26 26 52 52
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $7,725 $17,896 $20,795 $27,706
======== ======== ======== ========
The common stock of TNC is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS NORTH COMPANY
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $137,214 $2,351 $71,942 $(30,763) $180,744
Common Stock Dividends (4,970) (4,970)
Preferred Stock Dividends (52) (52)
---------
TOTAL 175,722
---------
COMPREHENSIVE INCOME
- ------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (309) (309)
Minimum Pension Liability (7) (7)
NET INCOME 27,758 27,758
---------
TOTAL COMPREHENSIVE INCOME 27,442
--------- ------- --------- --------- ---------
JUNE 30, 2003 $137,214 $2,351 $94,678 $(31,079) $203,164
========= ======= ========= ========= =========
DECEMBER 31, 2003 $137,214 $2,351 $125,428 $(26,718) $238,275
Common Stock Dividends (2,000) (2,000)
Preferred Stock Dividends (52) (52)
---------
TOTAL 236,223
---------
COMPREHENSIVE INCOME
- ------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (3,164) (3,164)
NET INCOME 20,847 20,847
---------
TOTAL COMPREHENSIVE INCOME 17,683
--------- ------- --------- --------- ---------
JUNE 30, 2004 $137,214 $2,351 $144,223 $(29,882) $253,906
========= ======= ========= ========= =========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ----------------------------------------------------
Production $361,620 $360,463
Transmission 275,081 268,695
Distribution 465,965 456,278
General 120,557 117,792
Construction Work in Progress 25,582 30,199
----------- -----------
TOTAL 1,248,805 1,233,427
Accumulated Depreciation and Amortization 469,153 460,513
----------- -----------
TOTAL - NET 779,652 772,914
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ----------------------------------------------------
Non-Utility Property, Net 1,181 1,286
----------- -----------
TOTAL 1,181 1,286
----------- -----------
CURRENT ASSETS
- ----------------------------------------------------
Cash and Cash Equivalents 1,387 -
Other Cash Deposits 2,297 2,863
Advances to Affiliates 47,984 41,593
Accounts Receivable:
Customers 70,674 56,670
Affiliated Companies 18,759 28,910
Accrued Unbilled Revenues 3,537 4,871
Miscellaneous 521 3,411
Allowance for Uncollectible Accounts (85) (175)
Fuel Inventory 8,852 10,925
Materials and Supplies 8,619 8,866
Risk Management Assets 4,877 10,340
Margin Deposits 87 1,285
Prepayments and Other 1,477 1,834
----------- -----------
TOTAL 168,986 171,393
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ----------------------------------------------------
Regulatory Assets:
Deferred Fuel Costs 26,680 26,680
Deferred Debt - Restructuring 6,336 6,579
Unamortized Loss on Reacquired Debt 2,967 3,929
Other 2,949 3,332
Long-term Risk Management Assets 1,124 3,106
Deferred Charges 31,671 20,290
----------- -----------
TOTAL 71,727 63,916
----------- -----------
TOTAL ASSETS $1,021,546 $1,009,509
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ------------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares $137,214 $137,214
Paid-in Capital 2,351 2,351
Retained Earnings 144,223 125,428
Accumulated Other Comprehensive Income (Loss) (29,882) (26,718)
----------- -----------
Total Common Shareholder's Equity 253,906 238,275
Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,357 2,357
----------- -----------
Total Shareholder's Equity 256,263 240,632
Long-term Debt 314,306 314,249
----------- -----------
TOTAL 570,569 554,881
----------- -----------
CURRENT LIABILITIES
- ------------------------------------------------------------------
Long-term Debt Due Within One Year 18,469 42,505
Accounts Payable:
General 21,748 28,190
Affiliated Companies 44,168 40,601
Customer Deposits 998 161
Taxes Accrued 37,404 22,877
Interest Accrued 5,423 6,038
Risk Management Liabilities 7,780 8,658
Obligations Under Capital Leases 207 203
Other 7,247 9,419
----------- -----------
TOTAL 143,444 158,652
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ------------------------------------------------------------------
Deferred Income Taxes 111,087 113,019
Long-term Risk Management Liabilities 639 1,094
Regulatory Liabilities:
Asset Removal Costs 83,601 76,740
Deferred Investment Tax Credits 19,333 19,990
Retail Clawback 6,837 11,804
Excess Earnings 14,020 14,262
SFAS 109 Regulatory Liability, Net 12,855 13,655
Other 1,679 1,826
Obligations Under Capital Leases 282 270
Deferred Credits and Other 57,200 43,316
----------- -----------
TOTAL 307,533 295,976
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $1,021,546 $1,009,509
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS NORTH COMPANY
STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- -------------------------------------------------------
Net Income $20,847 $27,758
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (3,071)
Depreciation and Amortization 19,546 19,255
Deferred Income Taxes (2,767) (1,079)
Deferred Investment Tax Credits (656) (760)
Deferred Property Taxes (7,400) (6,645)
Mark-to-Market of Risk Management Contracts 1,955 (2,905)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 281 24,683
Fuel, Materials and Supplies 2,320 4,308
Accounts Payable (2,875) (61,985)
Taxes Accrued 14,527 16,134
Change in Other Assets (8,931) (5,976)
Change in Other Liabilities 14,538 12,909
-------- --------
Net Cash Flows From Operating Activities 51,385 22,626
-------- --------
INVESTING ACTIVITIES
- -------------------------------------------------------
Construction Expenditures (18,085) (21,609)
Change in Other Cash Deposits, Net 566 (1,383)
Other - 595
-------- --------
Net Cash Flows Used For Investing Activities (17,519) (22,397)
-------- --------
FINANCING ACTIVITIES
- -------------------------------------------------------
Change in Short-term Debt - Affiliates - (125,000)
Issuance of Long-term Debt - 222,455
Retirement of Long-term Debt (24,036) -
Change in Advances to Affiliates (6,391) (92,312)
Dividends Paid on Common Stock (2,000) (4,970)
Dividends Paid on Cumulative Preferred Stock (52) (52)
-------- --------
Net Cash Flows From (Used For) Financing Activities (32,479) 121
-------- --------
Net Increase in Cash and Cash Equivalents 1,387 350
Cash and Cash Equivalents at Beginning of Period - 62
-------- --------
Cash and Cash Equivalents at End of Period $1,387 $412
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $11,139,000 and $5,525,000 and for income taxes was $(412,000)
and $(1,305,000) in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
AEP TEXAS NORTH COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to TNC's financial statements are combined with the notes to
financial statements for other subsidiary registrants. Listed below are the
notes that apply to TNC. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income for the second quarter of 2004 increased $7 million from the prior
year period due to favorable results from risk management activities, increased
sales and decreased interest charges partially offset by increased Maintenance
expense and Income Taxes.
Net Income for the first six months of 2004 decreased $84 million from the prior
year period primarily due to the Cumulative Effect of Accounting Changes of $77
million recorded in 2003 and increased Maintenance and depreciation expenses
partially offset by favorable results from risk management activities and
decreased interest charges.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income for 2004 decreased $3 million from 2003 primarily due to the
following:
o A decrease in off-system sales and transmission revenues totaling $10
million.
o An increase in Maintenance expense of $16 million primarily due to planned
maintenance at Amos, Clinch River, and Glen Lyn plants relating to scheduled
outages in 2004.
o An $8 million increase in Income Taxes (see "Income Taxes" below).
o A decrease of $4 million in Sales to AEP Affiliates due to decreased power
available for sale caused by planned plant outages in 2004.
o An increase in Other Operation expense of $4 million primarily due to
increased allocated costs from AEPSC and higher employee-related benefits
costs in the second quarter of 2004.
The decrease in Operating Income for 2004 was partially offset by:
o An increase in retail sales of $22 million primarily as a result of
increased cooling degree days in the second quarter of 2004.
o An increase of $13 million due to favorable results from risk management
activities.
o A net $7 million decrease in Fuel and purchased electricity expense as a
$14 million decrease in Fuel expense was partially offset by increased
purchased electricity expense. The $14 million decrease in Fuel expense was
primarily due to decreased generation and deferred fuel expense partially
offset by the increased cost of coal used in generation.
Other Impacts on Earnings
- -------------------------
Nonoperating Income (Loss) increased $4 million in 2004 compared to 2003
primarily due to favorable results from risk management activities.
Interest charges decreased $9 million in the second quarter of 2004 from the
prior year period due to reduced interest rates from refunding higher cost debt
and increased Allowance for Funds Used During Construction in 2004.
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were 46.0% and
39.9%, 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, amortization of investment tax credits and
state income taxes. The increase in the effective tax rate is primarily due to
an investment tax credit adjustment as a result of the Virginia SCC extending
the regulatory transition period offset by lower state income taxes.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income for 2004 decreased $28 million from 2003 primarily due to the
following:
o A decrease in off-system sales and transmission revenues totaling
$6 million.
o An increase in Maintenance expense of $25 million primarily due to planned
maintenance at Amos, Clinch River, Glen Lyn and Kanawha River plants
relating to scheduled outages in 2004.
o A decrease of $7 million in Sales to AEP Affiliates due to decreased power
available for sale caused by planned plant outages in 2004.
o An increase in Depreciation and Amortization expense of $13 million
primarily due to reduced expense in 2003 attributable to the adoption of
SFAS 143 for regulated operations and to a lesser degree, a greater
depreciable base in 2004, which included the addition of capitalized
software costs.
o An increase in Other Operation expense of $10 million primarily due to
increased allocated costs from AEPSC and higher employee-related benefits
costs in 2004.
The decrease in Operating Income for 2004 was partially offset by:
o An increase in retail sales of $22 million primarily as a result of
increased cooling degree days in the second quarter of 2004.
o A net $7 million decrease in Fuel and purchased electricity expense as a
$23 million decrease in Fuel expense was partially offset by increased
purchased electricity expense. The $23 million decrease in Fuel expense was
primarily due to decreased generation and deferred fuel expense partially
offset by the increased cost of coal used in generation.
Other Impacts on Earnings
- -------------------------
Nonoperating Income (Loss) increased $14 million in 2004 compared to 2003
primarily due to favorable results from risk management activities.
Interest charges decreased $12 million in the first six months of 2004 from the
prior year due to reduced interest rates from refunding higher cost debt and
increased Allowance for Funds Used During Construction in 2004.
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were 40.2% and
37.3%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The increase in the effective tax rate is primarily due to
an investment tax credit adjustment as a result of the Virginia SCC extending
the regulatory transition period offset by federal income tax adjustments.
Cumulative Effect of Accounting Changes
- ---------------------------------------
The Cumulative Effect of Accounting Changes of $77 million is due to the
implementation of SFAS 143 and EITF 02-3 in 2003.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds Baa1 BBB A-
Senior Unsecured Debt Baa2 BBB BBB+
Cash Flow
- ---------
Cash flows for the six months ended June 30, 2004 and 2003 were as follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $4,561 $4,133
--------- ---------
Cash flow from (used for):
Operating activities 228,942 267,383
Investing activities (163,031) (113,170)
Financing activities (66,841) (147,840)
--------- ---------
Net increase (decrease) in cash and cash equivalents (930) 6,373
--------- ---------
Cash and cash equivalents at end of period $3,631 $10,506
========= =========
Operating Activities
- --------------------
Net Cash Flows From Operating Activities in the first six months of 2004 were
$229 million versus $267 million in 2003 due to changes in Accounts Receivable
and Accounts Payable, as well as increased purchases of emission allowances and
increased fuel inventory.
Investing Activities
- --------------------
Net Cash Flows Used For Investing Activities in the first six months of 2004
were $163 million. Current year construction expenditures of $204 million were
focused primarily on projects to improve service reliability for transmission
and distribution, as well as environmental upgrades. In addition, Changes in
Other Cash Deposits, Net of $41 million consisted primarily of monies set aside
in 2003 for the retirement of the Installment Purchase Contracts in 2004.
Financing Activities
- --------------------
In the first six months of 2004, we retired $40 million of Installment Purchase
Contracts and $45 million of First Mortgage Bonds, paid $50 million in dividends
and increased Advances from Affiliates by $69 million.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first six months of 2004
were:
Issuances
---------
None.
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $45,000 7.125 2024
Installment Purchase
Contracts 40,000 5.45 2019
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $68,066
(Gain) Loss from Contracts Realized/Settled During the Period (a) (23,158)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 601
Change in Fair Value Due to Valuation Methodology Changes (d) 835
Changes in Fair Value of Risk Management Contracts (e) 5,166
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f) 5,782
--------
Total MTM Risk Management Contract Net Assets 57,292
Net Cash Flow Hedge Contracts (g) (6,972)
DETM Assignment (h) (27,127)
--------
Total MTM Risk Management Contract Net Assets at June 30, 2004 $23,193
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather, etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(h) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(3,646) $362 $(10) $1,156 $- $- $(2,138)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 16,350 5,240 3,670 1,978 928 - 28,166
Prices Based on Models and Other Valuation
Methods (b) 289 5,929 2,754 4,839 4,912 12,541 31,264
-------- -------- ------- ------- ------- -------- --------
Total $12,993 $11,531 $6,414 $7,973 $5,840 $12,541 $57,292
======== ======== ======= ======= ======= ======== ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources, modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third- party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be market-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2004
Foreign
Power Currency Interest Rate Consolidated
----- -------- ------------- ------------
(in thousands)
Beginning Balance December 31, 2003 $359 $(183) $(1,745) $(1,569)
Changes in Fair Value (a) (2,971) - (705) (3,676)
Reclassifications from AOCI to Net
Income (b) (958) 3 169 (786)
-------- ------ -------- --------
Ending Balance June 30, 2004 $(3,570) $(180) $(2,281) $(6,031)
======== ====== ======== ========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $2,659 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
---------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$936 $2,122 $1,056 $529 $596 $2,314 $969 $230
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $111 million and $102 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period; therefore, a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
-------------------- ----------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ----------------------------------------------------------
Electric Generation, Transmission and Distribution $413,383 $389,255 $885,958 $868,588
Sales to AEP Affiliates 51,047 55,496 104,929 112,391
--------- --------- --------- ---------
TOTAL 464,430 444,751 990,887 980,979
--------- --------- --------- ---------
OPERATING EXPENSES
- ----------------------------------------------------------
Fuel for Electric Generation 98,694 112,680 209,405 232,545
Purchased Electricity for Resale 17,786 15,262 34,430 32,380
Purchased Electricity from AEP Affiliates 87,793 83,805 178,280 164,525
Other Operation 70,576 66,626 138,668 128,741
Maintenance 52,933 36,827 94,253 69,565
Depreciation and Amortization 47,231 46,065 95,144 82,073
Taxes Other Than Income Taxes 23,499 22,272 46,952 47,351
Income Taxes 19,836 12,158 60,276 62,059
--------- --------- --------- ---------
TOTAL 418,348 395,695 857,408 819,239
--------- --------- --------- ---------
OPERATING INCOME 46,082 49,056 133,479 161,740
Nonoperating Income (Loss) 3,540 (324) 9,087 (4,624)
Nonoperating Expenses 3,596 2,451 6,129 6,309
Nonoperating Income Tax Credit (1,263) (2,451) (1,625) (6,184)
Interest Charges 25,463 34,096 50,900 63,202
--------- --------- --------- ---------
Income Before Cumulative Effect of Accounting Changes 21,826 14,636 87,162 93,789
Cumulative Effect of Accounting Changes (Net of Tax) - - - 77,257
--------- --------- --------- ---------
NET INCOME 21,826 14,636 87,162 171,046
Preferred Stock Dividend Requirements (Including Capital
Stock Expense) 798 984 1,621 1,968
--------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $21,028 $13,652 $85,541 $169,078
========= ========= ========= =========
The common stock of APCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $260,458 $717,242 $260,439 $(72,082) $1,166,057
Common Stock Dividends (64,133) (64,133)
Preferred Stock Dividends (721) (721)
Capital Stock Expense 1,247 (1,247) -
SFAS 71 Reapplication 162 162
-----------
TOTAL 1,101,365
-----------
COMPREHENSIVE INCOME
- ------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (3,113) (3,113)
NET INCOME 171,046 171,046
-----------
TOTAL COMPREHENSIVE INCOME 167,933
--------- --------- --------- --------- -----------
JUNE 30, 2003 $260,458 $718,651 $365,384 $(75,195) $1,269,298
========= ========= ========= ========= ===========
DECEMBER 31, 2003 $260,458 $719,899 $408,718 $(52,088) $1,336,987
Common Stock Dividends (50,000) (50,000)
Preferred Stock Dividends (400) (400)
Capital Stock Expense 1,221 (1,221) -
-----------
TOTAL 1,286,587
-----------
COMPREHENSIVE INCOME
- ------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (4,462) (4,462)
NET INCOME 87,162 87,162
-----------
TOTAL COMPREHENSIVE INCOME 82,700
--------- --------- --------- --------- -----------
JUNE 30, 2004 $260,458 $721,120 $444,259 $(56,550) $1,369,287
========= ========= ========= ========= ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -------------------------------------------------------
Production $2,408,222 $2,287,043
Transmission 1,249,901 1,240,889
Distribution 2,033,834 2,006,329
General 302,053 294,786
Construction Work in Progress 321,620 311,884
----------- -----------
TOTAL 6,315,630 6,140,931
Accumulated Depreciation and Amortization 2,382,795 2,321,360
----------- -----------
TOTAL - NET 3,932,835 3,819,571
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- -------------------------------------------------------
Non-Utility Property, Net 20,457 20,574
Other Investments 22,938 26,668
----------- -----------
TOTAL 43,395 47,242
----------- -----------
CURRENT ASSETS
- -------------------------------------------------------
Cash and Cash Equivalents 3,631 4,561
Other Cash Deposits 705 41,320
Accounts Receivable:
Customers 136,105 133,717
Affiliated Companies 119,821 137,281
Accrued Unbilled Revenues 23,669 35,020
Miscellaneous 4,302 3,961
Allowance for Uncollectible Accounts (5,426) (2,085)
Fuel Inventory 60,580 42,806
Materials and Supplies 87,942 71,978
Risk Management Assets 91,267 71,189
Margin Deposits 3,974 11,525
Prepayments and Other 13,317 13,301
----------- -----------
TOTAL 539,887 564,574
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- -------------------------------------------------------
Regulatory Assets:
Transition Regulatory Assets 27,590 30,855
SFAS 109 Regulatory Asset, Net 324,233 325,889
Unamortized Loss on Reacquired Debt 19,696 19,005
Other Regulatory Assets 41,658 41,447
Long-term Risk Management Assets 83,507 70,900
Deferred Property Taxes 29,640 35,343
Other Deferred Charges 22,784 22,185
----------- -----------
TOTAL 549,108 545,624
----------- -----------
TOTAL ASSETS $5,065,225 $4,977,011
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- -------------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $260,458 $260,458
Paid-in Capital 721,120 719,899
Retained Earnings 444,259 408,718
Accumulated Other Comprehensive Income (Loss) (56,550) (52,088)
----------- -----------
Total Common Shareholder's Equity 1,369,287 1,336,987
Cumulative Preferred Stock Not Subject to Mandatory Redemption 17,784 17,784
----------- -----------
Total Shareholder's Equity 1,387,071 1,354,771
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption 5,360 5,360
Long-term Debt 1,128,920 1,703,073
----------- -----------
TOTAL 2,521,351 3,063,204
----------- -----------
CURRENT LIABILITIES
- ------------------------------------------------------
Long-term Debt Due Within One Year 651,008 161,008
Advances from Affiliates 151,558 82,994
Accounts Payable:
General 120,705 140,497
Affiliated Companies 65,734 81,812
Customer Deposits 45,552 33,930
Taxes Accrued 77,933 50,259
Interest Accrued 22,149 22,113
Risk Management Liabilities 83,792 51,430
Obligations Under Capital Leases 7,074 9,218
Other 54,460 60,289
----------- -----------
TOTAL 1,279,965 693,550
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- -------------------------------------------------------
Deferred Income Taxes 823,671 803,355
Regulatory Liabilities:
Asset Removal Costs 95,206 92,497
Deferred Investment Tax Credits 32,635 30,545
Over Recovery of Fuel Cost 69,312 68,704
Other Regulatory Liabilities 23,493 17,326
Long-term Risk Management Liabilities 67,789 54,327
Obligations Under Capital Leases 13,935 16,134
Asset Retirement Obligation 22,635 21,776
Deferred Credits and Other 115,233 115,593
----------- -----------
TOTAL 1,263,909 1,220,257
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $5,065,225 $4,977,011
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- --------------------------------------------------------
Net Income $87,162 $171,046
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (77,257)
Depreciation and Amortization 95,144 82,073
Deferred Income Taxes 24,377 2,305
Deferred Investment Tax Credits 2,090 (847)
Deferred Property Taxes 5,793 5,343
Deferred Power Supply Costs, Net 607 69,528
Mark to Market of Risk Management Contracts 5,615 19,433
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 29,423 64,565
Fuel, Materials and Supplies (33,738) 2,965
Accounts Payable (35,870) (79,628)
Taxes Accrued 27,674 33,303
Interest Accrued 36 2,255
Incentive Plan Accrued (1,940) (9,388)
Rate Stabilization Deferral - (75,601)
Change in Other Assets 9,952 3,483
Change in Other Liabilities 12,617 53,805
--------- ---------
Net Cash Flows From Operating Activities 228,942 267,383
--------- ---------
INVESTING ACTIVITIES
- --------------------------------------------------------
Construction Expenditures (204,225) (114,806)
Proceeds from Sale of Property and Other 579 1,648
Change in Other Cash Deposits, Net 40,615 (12)
--------- ---------
Net Cash Flows Used For Investing Activities (163,031) (113,170)
--------- ---------
FINANCING ACTIVITIES
- --------------------------------------------------------
Issuance of Long-term Debt - 495,122
Retirement of Long-term Debt (85,005) (420,238)
Change in Advances from Affiliates, Net 68,564 (157,870)
Dividends Paid on Common Stock (50,000) (64,133)
Dividends Paid on Cumulative Preferred Stock (400) (721)
--------- ---------
Net Cash Flows Used For Financing Activities (66,841) (147,840)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (930) 6,373
Cash and Cash Equivalents at Beginning of Period 4,561 4,133
--------- ---------
Cash and Cash Equivalents at End of Period $3,631 $10,506
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $46,739,000 and $56,152,000 and for income taxes was $3,946,000 and
$21,102,000 in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to APCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below
are the notes that apply to APCo. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
The increase in Net Income of $1 million in second quarter 2004 was primarily
due to a $25 million increase in operating revenue, partially offset by a $9
million increase in fuel expense and a combined $15 million increase in other
operating expenses.
The decrease in year-to-date Net Income of $19 million in 2004 compared to 2003
was primarily due to a $27 million net-of-tax Cumulative Effect of Accounting
Changes in the first quarter of 2003, a $7 million increase in fuel expense,
combined increases of $20 million in other operating expenses and a $5 million
increase in Nonoperating Income Tax Expense, which was partially offset by
increases of $28 million in operating revenues and $14 million in nonoperating
risk management activities.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income increased $1 million primarily due to:
o An increase of $21 million in retail electric revenues resulting from
increased weather-related demand from residential and commercial customers
and an increase in customer base.
o An increase of $10 million in operating revenues related to favorable
results from risk management activities.
The increase in Operating Income was partially offset by:
o A decrease of $7 million in non-affiliated wholesale energy sales due to
lower sales volume and the expiration of municipal contracts.
o An increase of $9 million in fuel expense due to increased electric
generation and higher fuel costs per KWH.
o An increase of $7 million in Other Operation expense primarily relating to
uncollectible accounts, pension plan costs and increased allocated costs
from AEPSC.
o An increase of $3 million in Maintenance expense due primarily to boiler
overhaul work from scheduled and forced outages and increased overhead
distribution line expenses.
o An increase of $3 million in Depreciation and Amortization expenses due to
a greater depreciable base in 2004, including capital software costs
allocated from AEPSC and the increased amortization of regulatory assets
due to a federal tax adjustment to the asset account and quarterly
adjustments to the amortization rate.
o An increase of $2 million in Taxes Other than Income Taxes due to increased
state excise taxes.
Other Impacts on Earnings
- -------------------------
Nonoperating Income Tax Expense decreased $1 million. See Income Taxes section
below for further discussion.
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were 33.6% and
34.2%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to the flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The effective tax rates remained relatively flat for the
comparative period.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income increased $1 million primarily due to:
o An increase of $30 million in retail electric revenues resulting primarily
from increased weather-related demand from residential and commercial
customers during the second quarter 2004.
o An increase of $8 million in operating revenues related to favorable results
from risk management activities.
The increase in Operating Income was partially offset by:
o A decrease of $9 million in non-affiliated wholesale energy sales due to
lower sales volume and the expiration of municipal contracts.
o An increase of $7 million in Fuel for Electric Generation due to increased
electric generation and higher fuel costs per KWH.
o An increase of $8 million in Other Operation expense primarily relating to
uncollectible accounts, pension plan costs and increased allocated costs
from AEPSC.
o An increase of $6 million in Maintenance expense due primarily to boiler
overhaul work from scheduled and forced outages and increased overhead and
underground line expenses.
o An increase of $6 million in Depreciation and Amortization expenses due to
a greater depreciable base in 2004, including capital software costs
allocated from AEPSC and the increased amortization of regulatory assets
due to a federal tax adjustment to the asset account and quarterly
adjustment to the amortization rate.
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $12 million primarily due to favorable results
from risk management activities.
Nonoperating Income Tax Expense increased $5 million. See Income Taxes section
below for further discussion.
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were 35.1% and
34.1%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to the flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The effective tax rates remained relatively flat for the
comparative period.
Cumulative Effect of Accounting Changes
- ---------------------------------------
The Cumulative Effect of Accounting Changes is due to the one-time, after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 BBB A
Senior Unsecured Debt A3 BBB A-
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first six months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- ------- ----
(in thousands) (%)
Installment Purchase Contracts $43,695 Variable 2038
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $11,000 7.60 2024
Installment Purchase Contracts 43,695 6.25 2020
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $38,337
(Gain) Loss from Contracts Realized/Settled During the Period (a) (13,471)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 369
Change in Fair Value Due to Valuation Methodology Changes (d) 898
Changes in Fair Value of Risk Management Contracts (e) 9,080
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f) -
--------
Total MTM Risk Management Contract Net Assets 35,213
Net Cash Flow Hedge Contracts (g) (3,375)
DETM Assignment (h) (16,673)
--------
Total MTM Risk Management Contract Net Assets at June 30, 2004 $15,165
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather, etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(h) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ---- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(2,241) $223 $(6) $711 $- $- $(1,313)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 10,050 3,220 2,256 1,216 570 - 17,312
Prices Based on Models and Other
Valuation Methods (b) 175 3,644 1,693 2,974 3,020 7,708 19,214
-------- ------- ------- ------- ------- ------- --------
Total $7,984 $7,087 $3,943 $4,901 $3,590 $7,708 $35,213
======== ======= ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over-the-counter brokers, industry services, or
multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" if there is absence of
pricing information from external sources, modeled information is derived
using valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices for
underlying commodities beyond the period that prices are available from
third-party sources. In addition, where external pricing information or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for
placing it in the modeled category varies by market.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $202
Changes in Fair Value (a) (1,796)
Reclassifications from AOCI to Net Income (b) (601)
--------
Ending Balance June 30, 2004 $(2,195)
========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,404 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Energy and Gas Risk Management Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
---------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$575 $1,304 $649 $325 $336 $1,303 $546 $130
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $85 million and $98 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
-------------------- ---------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- -----------------------------------------------------
Electric Generation, Transmission and Distribution $336,793 $313,359 $680,479 $651,796
Sales to AEP Affiliates 21,333 19,712 39,952 40,480
--------- --------- --------- ---------
TOTAL 358,126 333,071 720,431 692,276
--------- --------- --------- ---------
OPERATING EXPENSES
- -----------------------------------------------------
Fuel for Electric Generation 51,159 37,924 92,796 85,464
Fuel From Affiliates for Electric Generation 1,755 6,100 10,603 10,603
Purchased Electricity for Resale 4,769 4,012 9,450 8,210
Purchased Electricity from AEP Affiliates 85,706 87,590 167,421 169,739
Other Operation 58,796 52,294 116,277 108,679
Maintenance 25,944 22,612 42,770 37,171
Depreciation and Amortization 36,445 33,299 73,263 67,036
Taxes Other Than Income Taxes 32,726 30,954 68,052 66,562
Income Taxes 16,197 14,869 40,662 40,244
--------- --------- --------- ---------
TOTAL 313,497 289,654 621,294 593,708
--------- --------- --------- ---------
OPERATING INCOME 44,629 43,417 99,137 98,568
Nonoperating Income (Loss) 770 311 5,848 (6,365)
Nonoperating Expenses 859 584 1,593 2,785
Nonoperating Income Tax Expense (Credit) (628) 400 291 (5,147)
Interest Charges 14,413 13,413 27,227 26,875
--------- --------- --------- ---------
Income Before Cumulative Effect of Accounting Changes 30,755 29,331 75,874 67,690
Cumulative Effect of Accounting Changes (Net of Tax) - - - 27,283
--------- --------- --------- ---------
NET INCOME 30,755 29,331 75,874 94,973
Preferred Stock - Capital Stock Expense 254 254 508 508
--------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $30,501 $29,077 $75,366 $94,465
========= ========= ========= =========
The common stock of CSPCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $41,026 $575,384 $290,611 $(59,357) $847,664
Common Stock Dividends Declared (86,622) (86,622)
Capital Stock Expense 508 (508) -
---------
TOTAL 761,042
---------
COMPREHENSIVE INCOME
- -------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,193) (1,193)
NET INCOME 94,973 94,973
---------
TOTAL COMPREHENSIVE INCOME 93,780
-------- --------- --------- --------- ---------
JUNE 30, 2003 $41,026 $575,892 $298,454 $(60,550) $854,822
======== ========= ========= ========= =========
DECEMBER 31, 2003 $41,026 $576,400 $326,782 $(46,327) $897,881
Common Stock Dividends Declared (62,500) (62,500)
Capital Stock Expense 508 (508) -
---------
TOTAL 835,381
---------
COMPREHENSIVE INCOME
- -------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (2,397) (2,397)
NET INCOME 75,874 75,874
---------
TOTAL COMPREHENSIVE INCOME 73,477
-------- --------- --------- --------- ---------
JUNE 30, 2004 $41,026 $576,908 $339,648 $(48,724) $908,858
======== ========= ========= ========= =========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -----------------------------------------------------
Production $1,645,647 $1,610,888
Transmission 429,803 425,512
Distribution 1,274,698 1,253,760
General 169,716 166,002
Construction Work in Progress 103,740 114,281
----------- -----------
TOTAL 3,623,604 3,570,443
Accumulated Depreciation and Amortization 1,430,860 1,389,586
----------- -----------
TOTAL - NET 2,192,744 2,180,857
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- -----------------------------------------------------
Non-Utility Property, Net 21,771 22,417
Other Investments 6,889 8,663
----------- -----------
TOTAL 28,660 31,080
----------- -----------
CURRENT ASSETS
- -----------------------------------------------------
Cash and Cash Equivalents 2,943 3,377
Other Cash Deposits 747 765
Accounts Receivable:
Customers 43,660 47,099
Affiliated Companies 54,861 68,168
Accrued Unbilled Revenues 19,388 23,723
Miscellaneous 6,533 5,257
Allowance for Uncollectible Accounts (1,209) (531)
Fuel 26,019 14,365
Materials and Supplies 66,754 44,377
Risk Management Assets 55,556 40,095
Margin Deposits 2,500 6,636
Prepayments and Other 12,681 12,444
----------- -----------
TOTAL 290,433 265,775
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- -----------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Assets, Net 16,209 16,027
Transition Regulatory Assets 172,780 188,532
Unamortized Loss on Reacquired Debt 13,538 13,659
Other 22,477 24,966
Long-term Risk Management Assets 51,328 39,932
Deferred Property Taxes 31,499 62,262
Deferred Charges 17,644 15,276
----------- -----------
TOTAL 325,475 360,654
----------- -----------
TOTAL ASSETS $2,837,312 $2,838,366
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
----- ----
(in thousands)
CAPITALIZATION
- ---------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $41,026 $41,026
Paid-in Capital 576,908 576,400
Retained Earnings 339,648 326,782
Accumulated Other Comprehensive Income (Loss) (48,724) (46,327)
----------- -----------
Total Common Shareholder's Equity 908,858 897,881
Long-term Debt 838,654 886,564
----------- -----------
TOTAL 1,747,512 1,784,445
----------- -----------
CURRENT LIABILITIES
- ---------------------------------------------------
Long-term Debt Due Within One Year 48,550 11,000
Advances from Affiliates, Net 5,959 6,517
Accounts Payable:
General 51,619 58,220
Affiliated Companies 40,089 53,572
Customer Deposits 26,472 19,727
Taxes Accrued 114,063 132,853
Interest Accrued 16,533 16,528
Risk Management Liabilities 50,829 28,966
Obligations Under Capital Leases 3,834 4,221
Other 22,858 25,364
----------- -----------
TOTAL 380,806 356,968
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ---------------------------------------------------
Deferred Income Taxes 466,032 458,498
Regulatory Liabilities:
Asset Removal Costs 101,441 99,119
Deferred Investment Tax Credits 29,324 30,797
Long-term Risk Management Liabilities 40,890 30,598
Obligations Under Capital Leases 9,672 11,397
Asset Retirement Obligations 9,085 8,740
Deferred Credits and Other 52,550 57,804
----------- -----------
TOTAL 708,994 696,953
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $2,837,312 $2,838,366
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------
Net Income $75,874 $94,973
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (27,283)
Depreciation and Amortization 73,263 67,036
Deferred Income Taxes 8,642 (3,135)
Deferred Investment Tax Credits (1,473) (1,526)
Deferred Property Taxes 31,039 30,973
Mark-to-Market of Risk Management Contracts 1,611 19,215
Gain on Sale of Assets (1,786) -
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 20,483 34,337
Fuel, Materials and Supplies (34,031) 1,005
Accounts Payable (20,084) (39,326)
Taxes Accrued (18,790) (24,796)
Interest Accrued 5 7,669
Change in Other Assets 3,976 (9,835)
Change in Other Liabilities 360 502
-------- --------
Net Cash Flows From Operating Activities 139,089 149,809
-------- --------
INVESTING ACTIVITIES
- ------------------------------------------------------
Construction Expenditures (67,148) (65,492)
Proceeds from Sale of Property and Other 2,265 190
Change in Other Cash Deposits, Net 18 (6)
-------- --------
Net Cash Flows Used For Investing Activities (64,865) (65,308)
-------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated 43,095 494,350
Change in Advances to/from Affiliates, Net (558) 146,271
Retirement of Long-term Debt - Nonaffiliated (54,695) (182,500)
Retirement of Long-term Debt - Affiliated - (160,000)
Change in Short-term Debt - Affiliates - (290,000)
Dividends Paid on Common Stock (62,500) (86,622)
-------- --------
Net Cash Flows Used For Financing Activities (74,658) (78,501)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (434) 6,000
Cash and Cash Equivalents at Beginning of Period 3,377 697
-------- --------
Cash and Cash Equivalents at End of Period $2,943 $6,697
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $25,131,000 and $18,442,000 and for income taxes was $(3,747,000)
and $(9,245,000) in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to CSPCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below
are the notes that apply to CSPCo. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
-----------------------------------------------
Results of Operations
- ---------------------
Net Income increased $28 million for the second quarter of 2004 and $44 million
for the first six months of 2004. The increases in Net Income reflect
improvement in retail sales, the end of amortization of Cook Plant outage
settlements and reduced financing charges in both the quarter and year-to-date
periods and favorable results from risk management activities for the
year-to-date period.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income increased $24 million primarily due to:
o An $18 million increase in retail revenues due primarily to a
weather-related increase in residential and commercial sales, an
improvement in industrial sales reflecting the recovering economy and the
end of amortization of Cook outage settlements.
o A $6 million increase in wholesale sales, including favorable results from
risk management activities.
o The increased availability of the Cook Plant that resulted in a $5
million increase in Sales to Affiliates and an $8 million decrease in
Purchased Electricity from AEP affiliates.
The increase in Operating Income was partially offset by:
o A $4 million increase in Maintenance expense due primarily to the cost of
a forced outage at Rockport Plant Unit 2, a planned outage at Tanner's Creek
Plant Unit 1 and storm damage expenses in May and June of 2004.
o A $3 million increase in Taxes Other Than Income Taxes primarily due to
favorable property tax adjustments that were recorded in 2003.
o A $9 million increase in Income Taxes. See Income Taxes section below for
further discussion.
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $4 million due to favorable results from risk
management activities and increased barging revenues from nonaffiliated
companies.
Nonoperating Expenses increased $2 million mainly due to increased expenses
related to increased barging revenues from nonaffiliated companies.
Nonoperating Income Taxes increased $2 million. See Income Taxes section below
for further discussion.
Interest Charges decreased $4 million primarily due to a reduction in
outstanding long-term debt and due to lower interest rates from refunding higher
cost debt.
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were 36.7% and
135.4%, 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, amortization of investment tax credits and
state income taxes. The change in the effective tax rate is primarily due to
lower pre-tax income in 2003 offsetting the effect of flow-through and permanent
differences, and state income taxes.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income increased $22 million primarily due to:
o A $27 million increase in Electric Generation, Transmission and
Distribution revenues due to an increase in residential and commercial sales
reflecting warmer spring weather in 2004, an improvement in industrial
sales reflecting an improvement in the economy and the end of amortization
of Cook Plant outage settlements.
o A $9 million decrease in Fuel for Electric Generation expense reflecting a
change in fuel mix as nuclear generation increased 48% and coal-fired
generation declined 18% due to generating unit availability.
o A $10 million decrease in Purchased Electricity from AEP Affiliates
primarily due to a 10% increase in net generation.
o A decrease of $4 million in Other Operation expense which included the end
of amortization of Cook Plant outage settlements.
The increase in Operating Income was partially offset by:
o A $7 million decrease in Sales to AEP Affiliates due to lower capacity
revenues.
o A $10 million increase in Maintenance expense due primarily to both planned
and forced outages at Rockport Plant Unit 2, a planned outage at Tanner's
Creek Plant Unit 1 and increased cost of storm damage in May and June of
2004.
o A $2 million increase in Taxes Other Than Income Taxes primarily due to
favorable property tax adjustments recorded in 2003 offset by decreased
Federal Insurance Contributions Act tax reflecting a reduction in employees
from the sustained earnings improvement initiative and timing of payroll
accrual.
o A $13 million increase in Income Taxes. See Income Taxes section below for
further discussion.
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $19 million primarily due to favorable results
from risk management activities.
Nonoperating Income Tax increased $8 million. See Income Taxes section below for
further discussion.
Interest Charges decreased $9 million primarily due to a reduction in
outstanding long-term debt and due to lower interest rates from refunding higher
cost debt.
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were 37.3% and
41.8%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The decrease in the effective tax rate is primarily due to
lower pre-tax income in 2003 offsetting the effect of flow-through and permanent
differences, and state income taxes.
Cumulative Effect of Accounting Change
- --------------------------------------
The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 related to mark-to-market accounting for risk
management contracts that are not derivatives.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds Baa1 BBB BBB+
Senior Unsecured Debt Baa2 BBB BBB
Cash Flow
- ---------
Cash flows for the first six months of 2004 and 2003 were as follows:
2004 2003
---- ----
(in thousands)
--------- --------
Cash and cash equivalents at beginning of period $3,899 $3,251
--------- --------
Cash flow from (used for):
Operating activities 260,645 88,838
Investing activities (78,054) (70,850)
Financing activities (183,319) (15,513)
--------- --------
Net increase (decrease) in cash and cash equivalents (728) 2,475
--------- --------
Cash and cash equivalents at end of period $3,171 $5,726
========= ========
Operating Activities
- --------------------
Operating activities during 2004 provided $172 million more cash than during
2003 largely due to increased net income of $44 million and improved working
capital requirements.
Investing Activities
- --------------------
Cash Flows Used For Investing Activities during 2004 were $7 million higher than
2003 primarily due to increased construction expenditures. Construction
expenditures for transmission and distribution assets were incurred to upgrade
or replace equipment and improve reliability.
Financing Activities
- --------------------
Financing activities for 2004 used $168 million more cash from operations than
during 2003 primarily to reduce short-term debt outstanding and pay common
dividends.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first six months of 2004
were:
Issuances
---------
None.
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $30,000 7.20 2024
First Mortgage Bonds 25,000 7.50 2024
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 arrangement
has not changed significantly from year-end 2003 and is comprised of a sale and
leaseback transaction entered into by AEGCo and I&M with an unrelated
unconsolidated trustee. 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 this off-balance
sheet arrangement see "Off-balance Sheet Arrangements" in "Management's
Financial Discussion and Analysis" section of our 2003 Annual Report.
Spent Nuclear Fuel Disposal
- ---------------------------
As a result of DOE's failure to make sufficient progress toward a permanent
repository or otherwise assume responsibility for spent nuclear fuel (SNF), we
and South Texas Project Nuclear Operating Company, along with a number of
unaffiliated utilities and states, filed suit in the D.C. Circuit Court
requesting, among other things, that the D.C. Circuit Court order DOE to meet
its obligations under the law. The D.C. Circuit Court ordered the parties to
proceed with contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, we filed a complaint in the U.S. Court of
Federal Claims seeking damages in excess of $150 million due to the DOE's
partial material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by
other utilities. In August 2000, in an appeal of related cases involving other
unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard contract between utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court. On January 17,
2003, the U.S. Court of Federal Claims ruled in our favor on the issue of
liability. The case continued on the issue of damages owed to us by the DOE. In
May 2004, the U.S. Court of Federal Claims ruled against us and denied damages,
which we intend to appeal. As long as the delay in the availability of the
government approved storage repository for SNF continues, the cost of both
temporary and permanent storage of SNF and the cost of decommissioning will
continue to increase. If such cost increases are not recovered on a timely basis
in regulated rates, future results of operations and cash flows could be
adversely affected.
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $41,995
(Gain) Loss from Contracts Realized/Settled During the Period (a) (13,076)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 404
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) 1,913
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) 7,641
--------
Total MTM Risk Management Contract Net Assets 38,877
Net Cash Flow Hedge Contracts (f) (4,394)
DETM Assignment (g) (18,276)
--------
Total MTM Risk Management Contract Net Assets at June 30, 2004 $16,207
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the Period"
represents the fair value of long-term contracts entered into with
customers during 2004. The fair value is calculated as of the
execution of the contract. Most of the fair value comes from longer
term fixed price contracts with customers that seek to limit their
risk against fluctuating energy prices. The contract prices are
valued against market curves associated with the delivery location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts that were entered into in 2004.
(d) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather, etc.
(e) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Operations. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(g) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(2,456) $244 $(7) $779 $- $- $(1,440)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 11,338 3,530 2,472 1,333 625 - 19,298
Prices Based on Models and Other
Valuation Methods (b) 150 3,994 1,856 3,260 3,310 8,449 21,019
-------- ------- ------- ------- ------- ------- --------
Total $9,032 $7,768 $4,321 $5,372 $3,935 $8,449 $38,877
======== ======= ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources" reflects information
obtained from over-the-counter brokers, industry services, or
multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources, modeled information is
derived using valuation models developed by the reporting entity,
reflecting when appropriate, option pricing theory, discounted cash flow
concepts, valuation adjustments, etc. and may require projection of
prices for underlying commodities beyond the period that prices are
available from third-party sources. In addition, where external pricing
information or market liquidity are limited, such valuations are
classified as modeled. The determination of the point at which a market
is no longer liquid for placing it in the modeled category varies by
market.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be market-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2004
Interest
Power Rate Consolidated
----- -------- ------------
(in thousands)
Beginning Balance December 31, 2003 $222 $- $222
Changes in Fair Value (a) (1,968) (351) (2,319)
Reclassifications from AOCI to Net Income (b) (659) - (659)
-------- ------ --------
Ending Balance June 30, 2004 $(2,405) $(351) $(2,756)
======== ====== ========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,557 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR the period indicated:
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
---------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$630 $1,430 $711 $357 $368 $1,429 $598 $142
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $88 million and $79 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
-------------------- ---------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ---------------------------------------------------
Electric Generation, Transmission and Distribution $339,874 $316,506 $693,272 $666,293
Sales to AEP Affiliates 65,025 60,400 122,670 129,211
--------- --------- --------- ---------
TOTAL 404,899 376,906 815,942 795,504
--------- --------- --------- ---------
OPERATING EXPENSES
- ---------------------------------------------------
Fuel for Electric Generation 65,582 65,763 129,623 138,857
Purchased Electricity for Resale 6,191 7,035 12,554 13,317
Purchased Electricity from AEP Affiliates 65,665 73,353 128,793 139,251
Other Operation 105,224 108,532 205,650 209,913
Maintenance 46,276 42,595 84,318 73,962
Depreciation and Amortization 42,696 42,841 85,411 86,567
Taxes Other Than Income Taxes 15,472 12,149 30,688 28,970
Income Taxes 14,798 5,409 39,097 26,448
--------- --------- --------- ---------
TOTAL 361,904 357,677 716,134 717,285
--------- --------- --------- ---------
OPERATING INCOME 42,995 19,229 99,808 78,219
Nonoperating Income 20,021 15,673 40,609 21,947
Nonoperating Expenses 17,331 15,287 32,182 30,877
Nonoperating Income Tax Expense (Credit) 878 (849) 2,491 (5,300)
Interest Charges 17,777 21,655 35,706 45,093
--------- --------- --------- ---------
Net Income (Loss) Before Cumulative Effect of Accounting Change 27,030 (1,191) 70,038 29,496
Cumulative Effect of Accounting Change (Net of Tax) - - - (3,160)
--------- --------- --------- ---------
NET INCOME (LOSS) 27,030 (1,191) 70,038 26,336
Preferred Stock Dividend Requirements (Including Capital
Stock Expense) 119 1,123 237 2,272
--------- --------- --------- ---------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $26,911 $(2,314) $69,801 $24,064
========= ========= ========= =========
The common stock of I&M is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $56,584 $858,560 $143,996 $(40,487) $1,018,653
Common Stock Dividends (20,000) (20,000)
Preferred Stock Dividends (2,205) (2,205)
Capital Stock Expense 67 (67) -
-----------
996,448
COMPREHENSIVE INCOME
- -----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,276) (1,276)
NET INCOME 26,336 26,336
-----------
TOTAL COMPREHENSIVE INCOME 25,060
-------- --------- --------- --------- -----------
JUNE 30, 2003 $56,584 $858,627 $148,060 $(41,763) $1,021,508
======== ========= ========= ========= ===========
DECEMBER 31, 2003 $56,584 $858,694 $187,875 $(25,106) $1,078,047
Common Stock Dividends (59,293) (59,293)
Preferred Stock Dividends (169) (169)
Capital Stock Expense 67 (67) -
-----------
1,018,585
COMPREHENSIVE INCOME
- -----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (2,978) (2,978)
NET INCOME 70,038 70,038
-----------
TOTAL COMPREHENSIVE INCOME 67,060
-------- --------- --------- --------- -----------
JUNE 30, 2004 $56,584 $858,761 $198,384 $(28,084) $1,085,645
======== ========= ========= ========= ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -----------------------------------------------------
Production $2,915,508 $2,878,051
Transmission 1,003,939 1,000,926
Distribution 969,804 958,966
General (including nuclear fuel) 263,738 274,283
Construction Work in Progress 189,638 193,956
----------- -----------
TOTAL 5,342,627 5,306,182
Accumulated Depreciation and Amortization 2,547,376 2,490,912
----------- -----------
TOTAL - NET 2,795,251 2,815,270
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- -----------------------------------------------------
Nuclear Decommissioning and Spent Nuclear Fuel
Disposal Trust Funds 1,013,050 982,394
Non-Utility Property, Net 50,824 52,303
Other Investments 31,608 43,797
----------- -----------
TOTAL 1,095,482 1,078,494
----------- -----------
CURRENT ASSETS
- -----------------------------------------------------
Cash and Cash Equivalents 3,171 3,899
Other Cash Deposits 55 15
Accounts Receivable:
Customers 56,158 63,084
Affiliated Companies 88,177 124,826
Miscellaneous 4,951 4,498
Allowance for Uncollectible Accounts (91) (531)
Fuel 34,959 33,968
Materials and Supplies 121,573 105,328
Risk Management Assets 61,545 44,071
Margin Deposits 2,728 7,245
Prepayments and Other 9,694 10,673
----------- -----------
TOTAL 382,920 397,076
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- -----------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 143,986 151,973
Incremental Nuclear Refueling Outage Expenses, Net 31,322 57,326
Other 74,049 66,978
Long-term Risk Management Assets 56,260 43,768
Deferred Property Taxes 20,896 21,916
Deferred Charges and Other Assets 31,487 26,270
----------- -----------
TOTAL 358,000 368,231
----------- -----------
TOTAL ASSETS $4,631,653 $4,659,071
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $56,584 $56,584
Paid-in Capital 858,761 858,694
Retained Earnings 198,384 187,875
Accumulated Other Comprehensive Income (Loss) (28,084) (25,106)
----------- -----------
Total Common Shareholder's Equity 1,085,645 1,078,047
Cumulative Preferred Stock - Not Subject to Mandatory Redemption 8,101 8,101
----------- -----------
Total Shareholder's Equity 1,093,746 1,086,148
Liability for Cumulative Preferred Stock - Subject to Mandatory
Redemption 61,445 63,445
Long-term Debt 1,135,993 1,134,359
----------- -----------
TOTAL 2,291,184 2,283,952
----------- -----------
CURRENT LIABILITIES
- ------------------------------------------------------------
Long-term Debt Due Within One Year 150,000 205,000
Advances from Affiliates 31,965 98,822
Accounts Payable:
General 75,425 101,776
Affiliated Companies 41,730 47,484
Customer Deposits 30,866 21,955
Taxes Accrued 86,512 42,189
Interest Accrued 16,986 17,963
Risk Management Liabilities 56,297 31,898
Obligations Under Capital Leases 6,053 6,528
Other 60,988 57,675
----------- -----------
TOTAL 556,822 631,290
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ------------------------------------------------------------
Deferred Income Taxes 326,660 337,376
Regulatory Liabilities:
Asset Removal Costs 269,921 263,015
Deferred Investment Tax Credits 86,614 90,278
Excess ARO for Nuclear Decommissioning 228,743 215,715
Other 71,339 61,268
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 68,325 70,179
Long-term Risk Management Liabilities 45,301 33,537
Obligations Under Capital Leases 29,262 31,315
Asset Retirement Obligations 572,786 553,219
Deferred Credits and Other 84,696 87,927
----------- -----------
TOTAL 1,783,647 1,743,829
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $4,631,653 $4,659,071
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- --------------------------------------------------------
Net Income $70,038 $26,336
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change - 3,160
Depreciation and Amortization 85,411 86,567
Deferred Income Taxes (524) (10,252)
Deferred Investment Tax Credits (3,664) (3,670)
Deferred Property Taxes 1,211 623
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses, Net 26,004 (8,799)
Unrecovered Fuel and Purchased Power Costs 1,171 18,751
Amortization of Nuclear Outage Costs - 20,000
Mark-to-Market of Risk Management Contracts 1,461 19,474
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 42,682 73,530
Fuel, Materials and Supplies (17,236) 1,599
Accounts Payable (32,105) (107,218)
Taxes Accrued 44,323 (19,201)
Change in Other Assets 12,014 (12,310)
Change in Other Liabilities 29,859 248
--------- ---------
Net Cash Flows From Operating Activities 260,645 88,838
--------- ---------
INVESTING ACTIVITIES
- --------------------------------------------------------
Construction Expenditures (78,014) (71,246)
Other - 415
Change in Other Cash Deposits, Net (40) (19)
--------- ---------
Net Cash Flows Used For Investing Activities (78,054) (70,850)
--------- ---------
FINANCING ACTIVITIES
- --------------------------------------------------------
Retirement of Cumulative Preferred Stock (2,000) (1,500)
Retirement of Long-term Debt - Nonaffiliated (55,000) (255,000)
Change in Advances to/from Affiliates, Net (66,857) 263,192
Dividends Paid on Common Stock (59,293) (20,000)
Dividends Paid on Cumulative Preferred Stock (169) (2,205)
--------- ---------
Net Cash Flows Used For Financing Activities (183,319) (15,513)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (728) 2,475
Cash and Cash Equivalents at Beginning of Period 3,899 3,251
--------- ---------
Cash and Cash Equivalents at End of Period $3,171 $5,726
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $34,825,000 and $44,812,000 and for income taxes was $189,000 and $50,731,000
in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to I&M's consolidated financial statements are combined with the notes
to financial statements for other subsidiary registrants. Listed below are the
notes that apply to I&M. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
KENTUCKY POWER COMPANY
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Net Income for the second quarter of 2004 was relatively flat compared to the
prior year period as increased retail revenues were essentially offset by
increased Maintenance expenses.
Net Income for the six months ended June 30, 2004 was up $2 million over 2003
primarily due to favorable results on risk management activities, partially
offset by the Cumulative Effect of Accounting Change recorded in 2003.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income for the second quarter of 2004 was up slightly over the prior
year period. The positive factors contributing to the change in Operating Income
for 2004 were:
o A $10 million increase in Electric Generation, Transmission and Distribution
revenues due to increased retail revenues due primarily to a weather
related increase in residential and commercial sales, an improvement in
industrial sales reflecting the recovering economy and the rate increase
in mid-2003 to recover the cost of emission control equipment.
o A 32% increase in the Big Sandy Plant's generation which led to a decline
in Purchases from AEP Affiliates of $4 million. The increase in generation
was due to planned plant outages in 2003 for the implementation of emission
control equipment.
o A $2 million decrease in Income Taxes (see "Income Taxes" below).
These increases in Operating Income were partially offset by:
o An increase in Fuel for Electric Generation expense of $10 million
resulting from a 32% increase in generation over the second quarter of 2003
and an increase in the average cost per ton of fuel consumed.
o An increase of $3 million in Maintenance expense related to planned outages
for boiler overhauls in the second quarter of 2004 and storm damages in the
second quarter of 2004.
o An increase in Depreciation and Amortization of $2 million in 2004 due to
the implementation of emission control equipment at the Big Sandy plant in
mid-2003.
o An increase in Other Operation expense of $1 million due to increased
allocated costs from AEPSC.
Other Impacts on Earnings
- -------------------------
Nonoperating Income (Loss) increased $1 million in the first quarter of 2004
compared to 2003 primarily due to favorable results from risk management
activities.
Interest Charges increased approximately $577 thousand primarily due to
increased long-term debt outstanding.
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were 21.7% and
30.6%, 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, amortization of investment tax credits and state income taxes. The
decrease in the effective tax rate is primarily due to lower state income taxes
offset by flow-through property-related differences.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income for 2004 was virtually unchanged from 2003. Items that
favorably impacted operating income were:
o A $13 million increase in Electric Generation, Transmission and Distribution
revenues due to increased retail revenues primarily related to the rate
increase in mid-2003 to recover the cost of emission control equipment.
o A decrease in Purchased Electricity from AEP Affiliates of $8 million
resulting from a 30% increase in Big Sandy's generation in 2004. The
increase in generation was due to planned plant outages in 2003 for the
implementation of emission control equipment.
o A $2 million decrease in Income Taxes (see "Income Taxes" below).
These increases in Operating Income were partially offset by:
o An increase in Fuel for Electric Generation expense of $13 million resulting
from a 30% increase in generation over 2003 and an increase in the average
cost per ton of fuel consumed.
o An increase in Other Operation expense of $2 million due to increased
allocated costs from AEPSC.
o An increase of $4 million in Maintenance expense related to planned outages
for boiler overhauls in 2004.
o An increase in Depreciation and Amortization of $4 million in 2004 due to
the implementation of emission control equipment at the Big Sandy plant in
mid-2003.
Other Impacts on Earnings
- -------------------------
Nonoperating Income (Loss) increased $5 million in 2004 compared to 2003
primarily due to favorable results from risk management activities.
Interest Charges increased $1 million primarily due to increased long-term debt
outstanding.
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were 32.2% and
35.1%, 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, amortization of investment tax credits and state income taxes. The
decrease in the effective tax rate is primarily due to lower state income taxes.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
Senior Unsecured Debt Baa2 BBB BBB
Financing Activity
- ------------------
There were no long-term debt issuances or retirements during the first six
months of 2004.
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $15,490
(Gain) Loss from Contracts Realized/Settled During the Period (a) (4,712)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 142
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) 406
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) 2,119
--------
Total MTM Risk Management Contract Net Assets 13,445
Net Cash Flow Hedge Contracts (f) (1,097)
DETM Assignment (g) (6,366)
--------
Total MTM Risk Management Contract Net Assets at June 30, 2004 $5,982
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and
unexpired option contracts that were entered into in 2004.
(d) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
etc.
(e) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Statements of Income. These
net gains (losses) are recorded as regulatory liabilities/assets
for those subsidiaries that operate in regulated jurisdictions.
(f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(g) See Note 17 "Related Party Transactions" in the 2003 Annual Report.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(855) $85 $(2) $271 $- $- $(501)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 3,837 1,230 862 464 218 - 6,611
Prices Based on Models and Other
Valuation Methods (b) 67 1,391 646 1,135 1,153 2,943 7,335
------- ------- ------- ------- ------- ------- --------
Total $3,049 $2,706 $1,506 $1,870 $1,371 $2,943 $13,445
======= ======= ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources, modeled information is
derived using valuation models developed by the reporting entity,
reflecting when appropriate, option pricing theory, discounted cash
flow concepts, valuation adjustments, etc. and may require projection
of prices for underlying commodities beyond the period that prices are
available from third-party sources. In addition, where external pricing
information or market liquidity are limited, such valuations are
classified as modeled. The determination of the point at which a market
is no longer liquid for placing it in the modeled category varies by
market.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2004
Power Interest Rate Consolidated
----- ------------- ------------
(in thousands)
Beginning Balance December 31, 2003 $82 $338 $420
Changes in Fair Value (a) (693) - (693)
Reclassifications from AOCI to Net
Income (b) (226) (43) (269)
------ ----- ------
Ending Balance June 30, 2004 $(837) $295 $(542)
====== ===== ======
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $450 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
---------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$220 $498 $248 $124 $136 $527 $220 $52
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $25 million and $29 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or financial position.
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
-------------------- ----------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------------
Electric Generation, Transmission and Distribution $94,034 $84,296 $200,935 $188,255
Sales to AEP Affiliates 12,373 11,168 18,985 19,303
-------- -------- --------- ---------
TOTAL 106,407 95,464 219,920 207,558
-------- -------- --------- ---------
OPERATING EXPENSES
- --------------------------------------------------------
Fuel for Electric Generation 25,224 15,439 46,118 33,386
Purchased Electricity from AEP Affiliates 31,817 36,152 65,123 73,547
Other Operation 13,153 11,695 26,280 23,832
Maintenance 10,214 7,161 17,539 13,926
Depreciation and Amortization 10,905 9,248 21,764 17,960
Taxes Other Than Income Taxes 2,395 2,077 4,723 4,442
Income Taxes 1,094 2,728 7,554 9,667
-------- -------- --------- ---------
TOTAL 94,802 84,500 189,101 176,760
-------- -------- --------- ---------
OPERATING INCOME 11,605 10,964 30,819 30,798
Nonoperating Income (Loss) 674 (547) 1,626 (2,945)
Nonoperating Expenses 466 113 1,779 362
Nonoperating Income Tax Expense (Credit) 33 (926) (94) (1,484)
Interest Charges 7,712 7,135 15,081 13,859
-------- -------- --------- ---------
Income Before Cumulative Effect of Accounting Change 4,068 4,095 15,679 15,116
Cumulative Effect of Accounting Change (Net of Tax) - - - (1,134)
-------- -------- --------- ---------
NET INCOME $4,068 $4,095 $15,679 $13,982
======== ======== ========= =========
The common stock of KPCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $50,450 $208,750 $48,269 $(9,451) $298,018
Common Stock Dividends (10,966) (10,966)
---------
TOTAL 287,052
---------
COMPREHENSIVE INCOME
- -------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (506) (506)
NET INCOME 13,982 13,982
---------
TOTAL COMPREHENSIVE INCOME 13,476
-------- --------- -------- -------- ---------
JUNE 30, 2003 $50,450 $208,750 $51,285 $(9,957) $300,528
======== ========= ======== ======== =========
DECEMBER 31, 2003 $50,450 $208,750 $64,151 $(6,213) $317,138
Common Stock Dividends (12,500) (12,500)
---------
TOTAL 304,638
---------
COMPREHENSIVE INCOME
- -------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (962) (962)
NET INCOME 15,679 15,679
---------
TOTAL COMPREHENSIVE INCOME 14,717
-------- --------- -------- -------- ---------
JUNE 30, 2004 $50,450 $208,750 $67,330 $(7,175) $319,355
======== ========= ======== ======== =========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -------------------------------------------------
Production $460,577 $457,341
Transmission 383,329 381,354
Distribution 433,655 425,688
General 59,248 68,041
Construction Work in Progress 12,507 17,322
----------- -----------
TOTAL 1,349,316 1,349,746
Accumulated Depreciation and Amortization 385,237 381,876
----------- -----------
TOTAL - NET 964,079 967,870
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- -------------------------------------------------
Non-Utility Property, Net 5,442 5,423
Other Investments 398 1,022
----------- -----------
TOTAL 5,840 6,445
----------- -----------
CURRENT ASSETS
- -------------------------------------------------
Cash and Cash Equivalents 695 863
Other Cash Deposits 17 23
Advances to Affiliates 3,522 -
Accounts Receivable:
Customers 21,279 21,177
Affiliated Companies 21,631 25,327
Accrued Unbilled Revenues 4,501 5,534
Miscellaneous 283 97
Allowance for Uncollectible Accounts (69) (736)
Fuel 11,309 9,481
Materials and Supplies 19,911 16,585
Risk Management Assets 21,211 16,200
Margin Deposits 961 2,660
Prepayments and Other 1,601 1,696
----------- -----------
TOTAL 106,852 98,907
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- -------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 102,853 99,828
Other Regulatory Assets 15,147 13,971
Long-term Risk Management Assets 20,995 16,134
Deferred Property Taxes 3,511 6,847
Other Deferred Charges 11,515 11,632
----------- -----------
TOTAL 154,021 148,412
----------- -----------
TOTAL ASSETS $1,230,792 $1,221,634
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
CAPATALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ----------------------------------------------------
Common Shareholder's Equity:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $50,450 $50,450
Paid-in Capital 208,750 208,750
Retained Earnings 67,330 64,151
Accumulated Other Comprehensive Income (Loss) (7,175) (6,213)
----------- -----------
Total Common Shareholder's Equity 319,355 317,138
----------- -----------
Long-term Debt:
Nonaffiliated 427,841 427,602
Affiliated 80,000 60,000
----------- -----------
Total Long-term Debt 507,841 487,602
----------- -----------
TOTAL 827,196 804,740
----------- -----------
CURRENT LIABILITIES
- ----------------------------------------------------
Advances from Affiliates - 38,096
Accounts Payable:
General 22,366 22,802
Affiliated Companies 19,928 22,648
Customer Deposits 12,671 9,894
Taxes Accrued 10,999 7,329
Interest Accrued 6,783 6,915
Risk Management Liabilities 20,613 11,704
Obligations Under Capital Leases 1,653 1,743
Other 7,979 8,628
----------- -----------
TOTAL 102,992 129,759
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ----------------------------------------------------
Deferred Income Taxes 219,244 212,121
Regulatory Liabilities:
Asset Removal Costs 28,492 26,140
Deferred Investment Tax Credits 7,370 7,955
Other Regulatory Liabilities 13,167 10,591
Long-term Risk Management Liabilities 15,611 12,363
Obligations Under Capital Leases 3,077 3,549
Deferred Credits and Other 13,643 14,416
----------- -----------
TOTAL 300,604 287,135
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $1,230,792 $1,221,634
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------
Net Income $15,679 $13,982
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change - 1,134
Depreciation and Amortization 21,764 17,960
Deferred Income Taxes 4,616 7,605
Deferred Investment Tax Credits (585) (587)
Deferred Property Taxes 3,424 3,150
Deferred Fuel Costs, Net (1,514) (932)
Loss on Sale of Assets 1,051 -
Mark-to-Market of Risk Management Contracts 1,064 6,697
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 3,774 12,065
Fuel, Materials and Supplies (5,154) (2,672)
Accounts Payable (3,156) (43,251)
Taxes Accrued 3,670 6,175
Change in Other Assets (4,165) (4,773)
Change in Other Liabilities 10,013 1,261
-------- --------
Net Cash Flows From Operating Activities 50,481 17,814
-------- --------
INVESTING ACTIVITIES
- ------------------------------------------------------
Construction Expenditures (18,075) (57,897)
Proceeds from Sales of Property and Other 1,538 298
Change in Other Cash Deposits, Net 6 (1)
-------- --------
Net Cash Flow Used for Investing Activities (16,531) (57,600)
-------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------
Issuance of Long-term Debt - Affiliated 20,000 74,263
Retirement of Long-term Debt - Nonaffiliated - (40,000)
Retirement of Long-term Debt - Affiliated - (15,000)
Change in Advances to/from Affiliates, Net (41,618) 30,876
Dividends Paid (12,500) (10,966)
-------- --------
Net Cash Flows From (Used For) Financing Activities (34,118) 39,173
-------- --------
Net Decrease in Cash and Cash Equivalents (168) (613)
Cash and Cash Equivalents at Beginning of Period 863 2,285
-------- --------
Cash and Cash Equivalents at End of Period $695 $1,672
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $14,625,000 and $13,245,000 and for income taxes was $658,000 and
$(5,537,000) in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
KENTUCKY POWER COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to KPCo's financial statements are combined with the notes to
financial statements for other subsidiary registrants. Listed below are the
notes that apply to KPCo. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
OHIO POWER COMPANY CONSOLIDATED
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Effective July 1, 2003, we consolidated JMG Funding, LP (JMG) as a result of the
implementation of FIN 46. OPCo now records the depreciation, interest and other
operating expenses of JMG and eliminates JMG's revenues against OPCo's operating
lease expenses. While there was no effect to net income as a result of
consolidation, some individual income statement captions were affected.
Net Income decreased $17 million for the quarter due primarily to a $16 million
decrease in Sales to AEP Affiliates. Net Income decreased $130 million
year-to-date primarily due to a $125 million Cumulative Effect of Accounting
Changes in the first quarter of 2003. Income Before Cumulative Effect of
Accounting Changes decreased $6 million year-to-date primarily due to a decrease
in Sales to AEP affiliates.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $17 million for the three months ended June 30, 2004
compared with the three months ended June 30, 2003 due to:
o A $16 million decrease in Sales to AEP Affiliates. The decrease is primarily
the result of a 29% decrease in MWH for affiliated system sales partially
offset by an increase in price per MWH. The decrease in MWH was primarily
a result of an increase in planned boiler overhauls.
o A $13 million decrease in non-affiliated wholesale energy sales due to lower
sales volumes.
o A $10 million increase in Other Operation expense primarily due to a $7
million pre-tax adjustment in 2003 to the workers' compensation reserve
related to the sale of coal companies coupled with an increase in allocated
costs from AEPSC.
o A $10 million increase in Depreciation and Amortization expense primarily
associated with the OPCo consolidation of JMG. Depreciation expense related
to the assets owned by JMG are now consolidated with OPCo (there was no
change in overall net income due to the consolidation of JMG). In addition,
the increase is a result of a greater depreciable base in 2004, including
capitalized software costs and the increased amortization of regulatory
assets due to a federal tax adjustment which increased the regulatory asset
amount and the corresponding amortization amount.
The decrease in Operating Income was partially offset by:
o A $10 million increase in retail electric revenues resulting from increased
weather-related demand from residential and commercial customers and
increased usage from industrial customers. Cooling degree days increased 59%
for the three months ended June 30, 2004 compared to three months ended
June 30, 2003.
o A $15 million increase due to favorable results from risk management
activities.
o An $8 million decrease in Fuel for Electric Generation due to decreased net
generation as a result of an increase in planned boiler overhauls.
Other Impacts of Earnings
- -------------------------
Nonoperating Income increased $48 million primarily due to sales of excess
energy purchased from Dow at the Plaquemine, Louisiana plant (discussed in Note
5) including the effects of a related affiliate agreement which eliminates
OPCo's market exposure related to the purchases from Dow. There was no change in
overall Net Income due to the agreement with Dow.
Nonoperating Expense increased $42 million primarily due to the agreement to
purchase excess energy from Dow at the Plaquemine, Louisiana plant (discussed in
Note 5). There was no change in overall Net Income due to the agreement with
Dow.
Interest Charges increased $11 million due primarily to the consolidation of JMG
and its associated debt along with issuance of additional long-term debt
subsequent to second quarter 2003. (There was no change in overall Net Income
due to the consolidation of JMG).
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were 33.0% and
33.2%, 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, amortization of investment tax credits and
state income taxes. The effective tax rates remained relatively flat for the
comparative period.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $7 million for the six months ended June 30, 2004
compared with the six months ended June 30, 2003 due to:
o A $20 million decrease in non-affiliated wholesale energy sales due to a
lower sales volume.
o A $9 million decrease in Sales to AEP Affiliates. The decrease is primarily
the result of a 7.5% decrease in MWH for affiliated system sales.
o A $5 million increase in Fuel for Electric Generation due to higher pricing
per MWH.
o A $7 million increase in Other Operation expense primarily due to a pre-tax
adjustment in 2003 to the workers' compensation reserve related to the
sale of coal companies.
o A $20 million increase in Depreciation and Amortization expense primarily
associated with the OPCo consolidation of JMG. Depreciation expense related
to the assets owned by JMG are consolidated with OPCo effective July 1,
2003 (there was no change in overall Net Income due to the consolidation of
JMG). In addition, the increase is a result of a greater depreciable base
in 2004, including capitalized software and the increased amortization of
regulatory assets due to a federal tax adjustment which increased the
regulatory asset amount and the corresponding amortization amount.
The decrease in Operating Income was partially offset by:
o A $17 million increase in retail electric revenues resulting from increased
weather-related demand from residential and commercial customers and
increased usage from industrial customers. Cooling degree days increased 59%
for the six months ended June 30, 2004 compared to the six months ended June
30, 2003.
o A $9 million increase due to favorable results from risk management
activities.
o An $11 million decrease in Purchased Electricity for Resale primarily due to
cessation of the Buckeye Transmission agreement on June 30, 2003. Prior to
this date, Ohio Edison interchange expenses were recorded in Purchased
Electricity for Resale. An associated offsetting decrease in Ohio Edison
revenue occurred in non affiliated sales for resale; therefore, there was no
effect to net income. In addition, the DOE Settlement Capacity Surcharge
related to Ohio Valley Electric surplus charges was included in rates
through April 30, 2003, no longer in effect for 2004.
o A $23 million decrease in Income Taxes. See Income Taxes section below for
further discussion.
Other Impacts of Earnings
- -------------------------
Nonoperating Income increased $68 million primarily due to sales of excess
energy purchased from Dow at the Plaquemine, Louisiana plant (discussed in Note
5) including the effects of a related affiliate agreement which eliminates
OPCo's market exposure related to the purchases from Dow. There was no change in
overall Net Income due to the agreement with Dow. In addition, in the first six
months of 2004 results from risk management activities were favorable compared
to losses that were incurred in the first six months of 2003.
Nonoperating Expense increased $38 million primarily due to the agreement to
purchase excess energy from Dow at the Plaquemine, Louisiana plant (discussed in
Note 5). There was no change in overall Net Income due to the agreement with
Dow.
Interest Charges increased $23 million due primarily to the consolidation of JMG
and its associated debt along with issuance of additional long-term debt
subsequent to second quarter 2003. (There was no change in overall Net Income
due to the consolidation of JMG).
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were 35.0% and
39.7%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to the flow-through of book versus tax
differences, permanent differences, amortization of investment tax credits and
state income taxes. The decrease in the effective tax rate is primarily due to
lower state income taxes.
Cumulative Effect of Accounting Changes
- ---------------------------------------
The Cumulative Effect of Accounting Changes during 2003 was due to the one-time
after-tax impact of adopting SFAS 143 and implementing the requirements of EITF
02-3.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 BBB A-
Senior Unsecured Debt A3 BBB BBB+
Cash Flow
- ---------
Cash flows for the six months ended June 30, 2004 and 2003 were as follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $7,233 $5,275
--------- ---------
Cash flows from (used for):
Operating activities 300,773 80,467
Investing activities (81,909) (114,485)
Financing activities (219,703) 37,408
--------- ---------
Net increase (decrease) in cash and cash equivalents (839) 3,390
--------- ---------
Cash and cash equivalents at end of period $6,394 $8,665
========= =========
Operating Activities
- --------------------
Cash Flows From Operating Activities for the first six months of 2004 increased
$220 million compared to the first six months of 2003. This is primarily due to
significant reductions in Accounts Payable balances during the second quarter of
2003 partially associated with a wind-down of risk management activities in that
year.
Investing Activities
- --------------------
Cash Flows Used For Investing Activities decreased by $33 million during the
first six months of 2004 compared with the first six months of 2003 due
primarily to the Change in Other Cash Deposits, Net primarily as a result of
monies set aside in 2003 for the retirement of Installment Purchase Contracts
in 2004.
Financing Activities
- --------------------
Cash Flows For Financing Activities used $220 million in the first six months of
2004 and provided $37 million in the first six months of 2003. This is primarily
due to a decrease in the change in Advances to/from Affiliates, Net, during the
first six months of 2004 as a result of becoming a net lender as opposed to a
net borrower.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first six months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Financing Obligations $6,080 5.77 2024
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase Contracts $50,000 6.85 2004
Senior Unsecured Notes 140,000 7.375 2004
Notes Payable 1,500 6.27 2009
Notes Payable 2,927 6.81 2008
First Mortgage Bonds 10,000 7.30 2024
Other
- -----
Power Generation Facility
- -------------------------
AEP has agreements with Juniper Capital L.P. (Juniper) under which Juniper
constructed and financed a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and leased the Facility to AEP. AEP has
subleased the Facility to the Dow Chemical Company (Dow). The Facility is a
Dow-operated "qualifying cogeneration facility" for purposes of PURPA.
Commercial operation of the Facility as required by the agreements between
Juniper, AEP and Dow was achieved on March 18, 2004.
Dow uses a portion of the energy produced by the Facility and sells the excess
energy. OPCo has agreed to purchase up to approximately 800 MW of such excess
energy from Dow. Because the Facility is a major steam supply for Dow, Dow is
expected to operate the Facility at certain minimum levels, and OPCo is
obligated to purchase the energy generated at those minimum operating levels
(expected to be approximately 270 MW).
OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel
Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and
Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in
excess of market. OPCo has entered an agreement with an affiliate that
eliminates OPCo's market exposure related to the PPA. AEP has guaranteed this
affiliate's performance under the agreement. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant to
the PPA that TEM rejected as non-conforming. Commercial operation for purposes
of the PPA began April 2, 2004.
On September 5, 2003, TEM and OPCo separately filed declaratory judgment actions
in the United States District Court for the Southern District of New York. OPCo
alleges that TEM has breached the PPA, and is seeking a determination of OPCo's
rights under the PPA. TEM alleges that the PPA never became enforceable, or
alternatively, that the PPA has already been terminated as the result of OPCo's
breaches. If the PPA is deemed terminated or found to be unenforceable by the
court, OPCo could be adversely affected to the extent it is unable to find other
purchasers of the power with similar contractual terms and to the extent OPCo
does not fully recover claimed termination value damages from TEM. The corporate
parent of TEM (Tractebel SA) has provided a limited guaranty.
On November 18, 2003, the above litigation was suspended pending final
resolution in arbitration of all issues pertaining to the protocols relating to
the dispatching, operation, and maintenance of the Facility and the sale and
delivery of electric power products. In the arbitration proceedings, TEM argued
that in the absence of mutually agreed upon protocols there were no commercially
reasonable means to obtain or deliver the electric power products and therefore
the PPA is not enforceable. TEM further argued that the creation of the
protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on
February 11, 2004 and concluded that the "creation of protocols" was not subject
to arbitration, but did not rule upon the merits of TEM's claim that the PPA is
not enforceable. Management believes the PPA is enforceable. The litigation is
now in the discovery phase.
On March 26, 2004, OPCo requested that TEM provide assurances of performance of
its future obligations under the PPA, but TEM refused to do so. As indicated
above, OPCo also gave notice to TEM and declared April 2, 2004 as the
"Commercial Operations Date." Despite OPCo's prior tenders of replacement
electric power products to TEM beginning May 1, 2003 and despite OPCo's tender
of electric power products from the Facility to TEM beginning April 2, 2004, TEM
refused to accept and pay for them under the terms of the PPA. On April 5, 2004,
OPCo gave notice to TEM that OPCo (i) was suspending performance of its
obligations under PPA, (ii) would be seeking a declaration from the New York
federal court that the PPA has been terminated and (iii) would be pursuing
against TEM and Tractebel SA under the guaranty damages and the full termination
payment value of the PPA.
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
- -------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.
Roll-Forward of MTM Risk Management Contract Net Assets
- -------------------------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $53,938
(Gain) Loss from Contracts Realized/Settled During the Period (a) (18,460)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 489
Change in Fair Value Due to Valuation Methodology Changes (d) 1,189
Changes in Fair Value of Risk Management Contracts (e) 9,965
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f) -
--------
Total MTM Risk Management Contract Net Assets 47,121
Net Cash Flow Hedge Contracts (g) (4,615)
DETM Assignment (h) (22,057)
--------
Total MTM Risk Management Contracts Net Assets at June 30, 2004 $20,449
========
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered into
with customers during 2004. The fair value is calculated as of the
execution of the contract. Most of the fair value comes from longer
term fixed price contracts with customers that seek to limit their
risk against fluctuating energy prices. The contract prices are
valued against market curves associated with the delivery location.
(c)"Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts that were entered into in 2004.
(d)"Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e)"Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
storage, etc.
(f)"Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(h)See Note 17 "Related Party Transactions" in the 2003 Annual Report.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(2,964) $295 $(8) $940 $- $- $(1,737)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 13,047 5,244 2,985 1,608 755 - 23,639
Prices Based on Models and Other
Valuation Methods (b) 199 4,653 2,240 3,935 3,995 10,197 25,219
-------- -------- ------- ------- ------- -------- --------
Total $10,282 $10,192 $5,217 $6,483 $4,750 $10,197 $47,121
======== ======== ======= ======= ======= ======== ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources, modeled information is
derived using valuation models developed by the reporting entity,
reflecting when appropriate, option pricing theory, discounted cash
flow concepts, valuation adjustments, etc. and may require projection
of prices for underlying commodities beyond the period that prices are
available from third-party sources. In addition, where external pricing
information or market liquidity are limited, such valuations are
classified as modeled. The determination of the point at which a market
is no longer liquid for placing it in the modeled category varies by
market.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, economic hedge contracts which are not
designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2004
Foreign
Power Currency Consolidated
----- -------- ------------
(in thousands)
Beginning Balance December 31, 2003 $268 $(371) $(103)
Changes in Fair Value (a) (2,454) - (2,454)
Reclassifications from AOCI to Net
Income (b) (795) 7 (788)
-------- ------ --------
Ending Balance June 30, 2004 $(2,981) $(364) $(3,345)
======== ====== ========
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,949 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
---------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$761 $1,725 $858 $430 $444 $1,724 $722 $172
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $170 million and $214 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period; therefore, a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
-------------------- --------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ----------------------------------------------------
Electric Generation, Transmission and Distribution $397,645 $387,892 $840,863 $838,779
Sales to AEP Affiliates 135,413 151,494 281,901 291,238
--------- --------- ---------- ----------
TOTAL 533,058 539,386 1,122,764 1,130,017
--------- --------- ---------- ----------
OPERATING EXPENSES
- ----------------------------------------------------
Fuel for Electric Generation 145,503 153,446 311,774 307,094
Purchased Electricity for Resale 14,155 17,453 26,338 36,845
Purchased Electricity from AEP Affiliates 23,169 24,429 42,472 47,212
Other Operation 94,334 84,641 184,919 177,622
Maintenance 56,733 53,411 90,784 88,868
Depreciation and Amortization 70,388 60,224 142,170 121,775
Taxes Other Than Income Taxes 43,646 39,613 90,836 86,768
Income Taxes 22,220 26,338 62,202 85,132
--------- --------- ---------- ----------
TOTAL 470,148 459,555 951,495 951,316
--------- --------- ---------- ----------
OPERATING INCOME 62,910 79,831 171,269 178,701
Nonoperating Income 52,882 4,823 69,812 2,099
Nonoperating Expenses 49,231 7,331 57,300 19,041
Nonoperating Income Tax Expense (Credit) (3,120) 1,564 1,967 (3,092)
Interest Charges 30,898 19,482 62,867 40,224
--------- --------- ---------- ----------
Income Before Cumulative Effect of Accounting Changes 38,783 56,277 118,947 124,627
Cumulative Effect of Accounting Changes (Net of Tax) - - - 124,632
--------- --------- ---------- ----------
NET INCOME 38,783 56,277 118,947 249,259
Preferred Stock Dividend Requirements 183 315 366 629
--------- --------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $38,600 $55,962 $118,581 $248,630
========= ========= ========== ==========
The common stock of OPCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $321,201 $462,483 $522,316 $(72,886) $1,233,114
Common Stock Dividends (83,867) (83,867)
Preferred Stock Dividends (629) (629)
-----------
TOTAL 1,148,618
-----------
COMPREHENSIVE INCOME
- ------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,576) (1,576)
Minimum Pension Liability 5,624 5,624
NET INCOME 249,259 249,259
-----------
TOTAL COMPREHENSIVE INCOME 253,307
--------- --------- --------- --------- -----------
JUNE 30, 2003 $321,201 $462,483 $687,079 $(68,838) $1,401,925
========= ========= ========= ========= ===========
DECEMBER 31, 2003 $321,201 $462,484 $729,147 $(48,807) $1,464,025
Common Stock Dividends (114,115) (114,115)
Preferred Stock Dividends (366) (366)
-----------
TOTAL 1,349,544
-----------
COMPREHENSIVE INCOME
- ------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (3,242) (3,242)
Minimum Pension Liability (3,942) (3,942)
NET INCOME 118,947 118,947
-----------
TOTAL COMPREHENSIVE INCOME 111,763
--------- --------- --------- --------- -----------
JUNE 30, 2004 $321,201 $462,484 $733,613 $(55,991) $1,461,307
========= ========= ========= ========= ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -----------------------------------------------------
Production $4,077,693 $4,029,515
Transmission 961,560 938,805
Distribution 1,178,394 1,156,886
General 251,549 245,434
Construction Work in Progress 158,402 160,675
----------- -----------
Total 6,627,598 6,531,315
Accumulated Depreciation and Amortization 2,548,729 2,485,947
----------- -----------
TOTAL - NET 4,078,869 4,045,368
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- -----------------------------------------------------
Non-Utility Property, Net 29,463 29,291
Other 20,215 24,264
----------- -----------
TOTAL 49,678 53,555
----------- -----------
CURRENT ASSETS
- -----------------------------------------------------
Cash and Cash Equivalents 6,394 7,233
Other Cash Deposits 65 51,017
Advances to Affiliates 168,140 67,918
Accounts Receivable:
Customers 109,095 100,960
Affiliated Companies 121,263 120,532
Accrued Unbilled Revenues 9,063 17,221
Miscellaneous 1,198 736
Allowance for Uncollectible Accounts (343) (789)
Fuel 90,009 77,725
Materials and Supplies 98,955 92,136
Risk Management Assets 78,637 56,265
Margin Deposits 3,849 9,296
Prepayments and Other 13,025 15,883
----------- -----------
TOTAL 699,350 616,133
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- -----------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 170,684 169,605
Transition Regulatory Assets 267,673 310,035
Unamortized Loss on Reacquired Debt 11,405 10,172
Other 23,450 22,506
Long-term Risk Management Assets 71,411 52,825
Deferred Property Taxes 36,677 67,469
Deferred Charges and Other Assets 38,112 26,850
----------- -----------
TOTAL 619,412 659,462
----------- -----------
TOTAL ASSETS $5,447,309 $5,374,518
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $321,201 $321,201
Paid-in Capital 462,484 462,484
Retained Earnings 733,613 729,147
Accumulated Other Comprehensive Income (Loss) (55,991) (48,807)
----------- -----------
Total Common Shareholder's Equity 1,461,307 1,464,025
Cumulative Preferred Stock Not Subject to Mandatory Redemption 16,644 16,645
----------- -----------
Total Shareholder's Equity 1,477,951 1,480,670
Liability for Cumulative Preferred Stock Subject to
Mandatory Redemption 5,000 7,250
Long-term Debt:
Nonaffiliated 1,610,480 1,608,086
Affiliated 200,000 -
----------- -----------
Total Long-term Debt 1,810,480 1,608,086
----------- -----------
TOTAL 3,293,431 3,096,006
----------- -----------
Minority Interest 15,187 16,314
----------- -----------
CURRENT LIABILITIES
- ------------------------------------------------------------
Short-term Debt - General 21,539 25,941
Long-term Debt Due Within One Year - Nonaffiliated 233,857 431,854
Accounts Payable:
General 124,813 104,874
Affiliated Companies 83,459 101,758
Customer Deposits 28,099 17,308
Taxes Accrued 153,485 132,793
Interest Accrued 45,320 45,679
Risk Management Liabilities 72,462 38,318
Obligations Under Capital Leases 8,847 9,624
Other 66,525 71,642
----------- -----------
TOTAL 838,406 979,791
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ------------------------------------------------------------
Deferred Income Taxes 935,192 933,582
Regulatory Liabilities:
Asset Removal Costs 104,409 101,160
Deferred Investment Tax Credits 14,118 15,641
Other - 3
Long-term Risk Management Liabilities 57,137 40,477
Deferred Credits 24,459 23,222
Obligations Under Capital Leases 21,826 25,064
Asset Retirement Obligations 44,338 42,656
Other 98,806 100,602
----------- -----------
TOTAL 1,300,285 1,282,407
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $5,447,309 $5,374,518
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- -------------------------------------------------------
Net Income $118,947 $249,259
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (124,632)
Depreciation and Amortization 142,170 121,775
Deferred Income Taxes 4,400 372
Deferred Investment Tax Credits (1,523) (1,525)
Deferred Property Taxes 31,099 29,337
Mark-to-Market of Risk Management Contracts 4,819 26,381
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (1,616) 4,259
Fuel, Materials and Supplies (19,103) (2,519)
Prepayments and Other 8,305 (20,542)
Accounts Payable 1,640 (153,474)
Customer Deposits 10,791 9,524
Taxes Accrued 20,692 16,297
Interest Accrued (359) 10,105
Change in Other Assets (11,397) (42,716)
Change in Other Liabilities (8,092) (41,434)
--------- ---------
Net Cash Flows From Operating Activities 300,773 80,467
--------- ---------
INVESTING ACTIVITIES
- -------------------------------------------------------
Construction Expenditures (134,001) (117,761)
Change in Other Cash Deposits, Net 50,952 -
Proceeds from Sale of Property and Other 1,140 3,276
--------- ---------
Net Cash Flows Used For Investing Activities (81,909) (114,485)
--------- ---------
FINANCING ACTIVITIES
- -------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated 6,080 494,375
Issuance of Long-term Debt - Affiliated 200,000 -
Change in Advances to/from Affiliates, Net (100,222) 232,881
Change in Short-term Debt, Net (4,402) -
Change in Short-term Debt - Affiliates, Net - (275,000)
Retirement of Long-term Debt - Nonaffiliated (204,427) (29,850)
Retirement of Long-term Debt - Affiliated - (300,000)
Retirement of Cumulative Preferred Stock (2,251) (502)
Dividends Paid on Common Stock (114,115) (83,867)
Dividends Paid on Cumulative Preferred Stock (366) (629)
--------- ---------
Net Cash Flows (Used For) From Financing Activities (219,703) 37,408
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (839) 3,390
Cash and Cash Equivalents at Beginning of Period 7,233 5,275
--------- ---------
Cash and Cash Equivalents at End of Period $6,394 $8,665
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $60,282,000 and $29,304,000 and for income taxes was $(8,420,000)
and $26,455,000 in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to OPCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below
are the notes that apply to OPCo. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
PUBLIC SERVICE COMPANY OF OKLAHOMA
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Net Income decreased $20 million for 2004 year-to-date, and $11 million for the
second quarter due mainly to increased expenses for power plant maintenance,
tree trimming, line clearance and storm damage repairs.
Fluctuations occurring in the retail portion of fuel and purchased power expense
generally do not impact operating income, as they are offset in revenues due to
the functioning of the fuel adjustment clause in Oklahoma.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $12 million primarily due to:
o Decreased retained margins of $2 million due mainly to decreased realization
of off-system sales.
o Decreased transmission revenues of $2 million due mainly to non-affiliated
transactions.
o Increased Other Operation expenses of $5 million primarily related to
affiliated ancillary services, general transmission and distribution related
expenses.
o Increased Maintenance expense of $11 million due mainly to increased power
plant maintenance and tree trimming, along with increased repairs due to
storm damage.
o Increased Taxes Other Than Income Taxes of $1 million due primarily to
higher property and unemployment related taxes, offset in part by
lower state franchise taxes.
The decrease in Operating Income was partially offset by:
o Increased retail base revenue of $8 million (5%), resulting mainly from
increased KWH sales of 8%. Heating and cooling degree-days increased 12%.
Other Impacts on Earnings
- -------------------------
Interest Charges decreased $2 million due to reduced interest rates from
refinancing higher cost debt.
Income Taxes
- ------------
The effective tax rates for the second quarter of 2004 and 2003 were 21.0% and
18.2%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The increase in the effective tax
rate is primarily due to higher state income taxes offset by lower pre-tax
income in 2004.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $24 million primarily due to:
o Decreased retained margins of $4 million due mainly to decreased realization
of off-system sales.
o Decreased transmission revenues of $3 million due mainly to non-affiliated
transactions.
o Increased Other Operation expenses of $17 million, of which $9 million was
transmission expense primarily related to a prior year true up for OATT
transmission recorded in 2004 resulting from revised data from ERCOT for the
years 2001-2003. Increased distribution expenses of $5 million resulting
mainly from a labor settlement and various inventory and tracking system
upgrades. Increased administrative and general expenses resulted from
outside services and employee related expenses.
o Increased Maintenance expense of $14 million due mainly to increased power
plant maintenance and tree trimming along with increased repairs due to
storm damage.
The decrease in Operating Income was partially offset by:
o Increased retail base revenue of $9 million (5%), resulting mainly from
increased KWH sales of 3%. Total heating and cooling degree-days decreased
9%, but overall customer usage not related to weather increased, as did the
number of customers.
Other Impacts on Earnings
- -------------------------
Interest Charges decreased $5 million due to reduced interest rates from
refinancing higher cost debt.
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were 78.1% and
15.3%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The increase in the effective tax
rate is primarily due to pre-tax income becoming a loss in 2004 and state income
taxes.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Our first mortgage
bonds were upgraded by S&P to A- due to a change in methodology at the agency.
Current ratings are as follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 A- A
Senior Unsecured Debt Baa1 BBB A-
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first six months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase Contracts $33,700 Variable 2014
Senior Unsecured Notes 50,000 4.70 2009
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Notes Payable to Trust $77,320 8.00 2037
Installment Purchase Contracts 33,700 4.875 2014
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $14,057
(Gain) Loss from Contracts Realized/Settled During the Period (a) (973)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 62
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) -
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) (9,327)
--------
Total MTM Risk Management Contract Net Assets 3,819
Net Cash Flow Hedge Contracts (f) (567)
--------
Total MTM Risk Management Contract Net Assets at June 30, 2004 $3,252
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period" includes
realized risk management contracts and related derivatives that settled
during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the Period"
represents the fair value of long-term contracts entered into with
customers during 2004. The fair value is calculated as of the execution
of the contract. Most of the fair value comes from longer term fixed
price contracts with customers that seek to limit their risk against
fluctuating energy prices. The contract prices are valued against market
curves associated with the delivery location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option premiums
paid/(received) as they relate to unexercised and unexpired option
contracts that were entered into in 2004.
(d) "Changes in Fair Value of Risk Management Contracts" represents the fair
value change in the risk management portfolio due to market fluctuations
during the current period. Market fluctuations are attributable to
various factors such as supply/demand, weather, storage, etc.
(e) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Statements of Operations. These
net gains (losses) are recorded as regulatory liabilities/assets for
those subsidiaries that operate in regulated jurisdictions.
(f) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ---- ---------
(in thousands)
Prices Actively Quoted -
Exchange Traded Contracts $(379) $38 $(1) $120 $- $- $(222)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 1,468 795 158 - - - 2,421
Prices Based on Models and Other
Valuation Methods (b) (90) 618 (45) 119 256 762 1,620
------ ------- ----- ----- ----- ----- -------
Total $999 $1,451 $112 $239 $256 $762 $3,819
====== ======= ===== ===== ===== ===== =======
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources, modeled information is
derived using valuation models developed by the reporting entity,
reflecting when appropriate, option pricing theory, discounted cash
flow concepts, valuation adjustments, etc. and may require projection
of prices for underlying commodities beyond the period that prices are
available from third-party sources. In addition, where external pricing
information or market liquidity are limited, such valuations are
classified as modeled. The determination of the point at which a market
is no longer liquid for placing it in the modeled category varies by
market.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, economic hedge contracts which are not
designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $156
Changes in Fair Value (a) (426)
Reclassifications from AOCI to Net Income (b) (100)
------
Ending Balance June 30, 2004 $(370)
======
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $236 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
---------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$97 $221 $110 $55 $258 $1,004 $420 $100
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $45 million and $66 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or financial position.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
-------------------- --------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ------------------------------------------------------
Electric Generation, Transmission and Distribution $228,653 $267,213 $432,696 $505,480
Sales to AEP Affiliates 2,954 10,023 6,096 14,418
--------- --------- --------- ---------
TOTAL 231,607 277,236 438,792 519,898
--------- --------- --------- ---------
OPERATING EXPENSES
- ------------------------------------------------------
Fuel for Electric Generation 87,006 135,395 176,091 238,569
Purchased Electricity for Resale 5,583 6,863 14,751 19,354
Purchased Electricity from AEP Affiliates 28,200 28,276 55,099 70,383
Other Operation 36,768 31,684 80,163 63,302
Maintenance 22,875 12,366 35,997 21,760
Depreciation and Amortization 22,159 21,359 44,335 42,853
Taxes Other Than Income Taxes 9,727 8,439 19,544 18,085
Income Taxes (Credits) 2,429 4,139 (4,904) 3,731
--------- --------- --------- ---------
TOTAL 214,747 248,521 421,076 478,037
--------- --------- --------- ---------
OPERATING INCOME 16,860 28,715 17,716 41,861
Nonoperating Income 127 72 371 722
Nonoperating Expense (Credit) 762 (276) 1,304 163
Nonoperating Income Tax (Credit) (467) (155) (859) (355)
Interest Charges 9,301 11,291 19,254 24,157
--------- --------- --------- ---------
NET INCOME (LOSS) 7,391 17,927 (1,612) 18,618
Preferred Stock Dividend Requirements 53 53 106 106
--------- --------- --------- ---------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $7,338 $17,874 $(1,718) $18,512
========= ========= ========= =========
The common stock of PSO is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $157,230 $180,016 $116,474 $(54,473) $399,247
Capital Contribution from Parent 50,000 50,000
Common Stock Dividends (7,500) (7,500)
Preferred Stock Dividends (106) (106)
Distribution of Investment in AEMT, Inc.
Preferred Shares to Parent (548) (548)
---------
TOTAL 441,093
---------
COMPREHENSIVE INCOME
- -----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (879) (879)
Minimum Pension Liability (58) (58)
NET INCOME 18,618 18,618
---------
TOTAL COMPREHENSIVE INCOME 17,681
--------- --------- --------- --------- ---------
JUNE 30, 2003 $157,230 $230,016 $126,938 $(55,410) $458,774
========= ========= ========= ========= =========
DECEMBER 31, 2003 $157,230 $230,016 $139,604 $(43,842) $483,008
Gain on Reacquired Preferred Stock 2 2
Common Stock Dividends (17,500) (17,500)
Preferred Stock Dividends (106) (106)
---------
TOTAL 465,404
---------
COMPREHENSIVE INCOME (LOSS)
- -----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (526) (526)
NET LOSS (1,612) (1,612)
---------
TOTAL COMPREHENSIVE INCOME (LOSS) (2,138)
--------- --------- --------- --------- ---------
JUNE 30, 2004 $157,230 $230,016 $120,388 $(44,368) $463,266
========= ========= ========= ========= =========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ------------------------------------------------
Production $1,068,770 $1,065,408
Transmission 453,936 451,292
Distribution 1,061,487 1,031,229
General 208,736 203,756
Construction Work in Progress 41,446 54,711
----------- -----------
TOTAL 2,834,375 2,806,396
Accumulated Depreciation and Amortization 1,097,590 1,069,216
----------- -----------
TOTAL - NET 1,736,785 1,737,180
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ------------------------------------------------
Non-Utility Property, Net 4,411 4,631
Other Investments - 2,320
----------- -----------
TOTAL 4,411 6,951
----------- -----------
CURRENT ASSETS
- ------------------------------------------------
Cash and Cash Equivalents 3,843 3,738
Other Cash Deposits 6,954 10,520
Accounts Receivable:
Customers 29,892 28,515
Affiliated Companies 20,889 19,852
Miscellaneous 3,017 -
Allowance for Uncollectible Accounts (27) (37)
Fuel Inventory 21,083 18,331
Materials and Supplies 38,930 38,125
Regulatory Asset for Under-recovered Fuel Costs 36,853 24,170
Risk Management Assets 6,632 18,586
Margin Deposits 374 4,351
Prepayments and Other 2,700 2,655
----------- -----------
TOTAL 171,140 168,806
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ------------------------------------------------
Regulatory Assets:
Unamortized Loss on Reacquired Debt 15,517 14,357
Other 12,351 14,342
Long-term Risk Management Assets 3,831 10,379
Deferred Charges 35,239 18,017
----------- -----------
TOTAL 66,938 57,095
----------- -----------
TOTAL ASSETS $1,979,274 $1,970,032
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- --------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued Shares: 10,482,000
Outstanding Shares: 9,013,000 $157,230 $157,230
Paid-in Capital 230,016 230,016
Retained Earnings 120,388 139,604
Accumulated Other Comprehensive Income (Loss) (44,368) (43,842)
----------- -----------
Total Common Shareholder's Equity 463,266 483,008
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,262 5,267
----------- -----------
Total Shareholder's Equity 468,528 488,275
Long-term Debt 447,018 490,598
----------- -----------
TOTAL 915,546 978,873
----------- -----------
CURRENT LIABILITIES
- --------------------------------------------------------------
Long-term Debt Due Within One Year 100,000 83,700
Advances from Affiliates 75,034 32,864
Accounts Payable:
General 64,367 48,808
Affiliated Companies 61,981 57,206
Customer Deposits 29,499 26,547
Taxes Accrued 35,068 27,157
Interest Accrued 3,447 3,706
Risk Management Liabilities 5,034 11,067
Obligations Under Capital Leases 494 452
Other 21,294 35,234
----------- -----------
TOTAL 396,218 326,741
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- --------------------------------------------------------------
Deferred Income Taxes 347,414 335,434
Long-Term Risk Management Liabilities 2,177 3,602
Regulatory Liabilities:
Asset Removal Costs 219,101 214,033
Deferred Investment Tax Credits 29,515 30,411
SFAS 109 Regulatory Liability, Net 23,719 24,937
Other 5,085 15,406
Obligations Under Capital Leases 620 558
Deferred Credits and Other 39,879 40,037
----------- -----------
TOTAL 667,510 664,418
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $1,979,274 $1,970,032
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------------
Net Income (Loss) $(1,612) $18,618
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows
From Operating Activities:
Depreciation and Amortization 44,335 42,853
Deferred Income Taxes 11,043 10,940
Deferred Investment Tax Credits (895) (895)
Deferred Property Taxes (17,295) (16,478)
Mark-to-Market of Risk Management Contracts 10,237 (12,340)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (5,441) (5,556)
Fuel, Materials and Supplies (3,557) 868
Accounts Payable 20,334 1,262
Taxes Accrued 7,911 5,780
Fuel Recovery (12,683) 11,650
Changes in Other Assets 157 (11,359)
Changes in Other Liabilities (16,478) 1,145
--------- --------
Net Cash Flows From Operating Activities 36,056 46,488
--------- --------
INVESTING ACTIVITIES
- ------------------------------------------------------------
Construction Expenditures (36,645) (34,660)
Proceeds from Sale of Property and Other 458 127
Change in Other Cash Deposits, Net 3,566 (2,843)
--------- --------
Net Cash Flows Used For Investing Activities (32,621) (37,376)
--------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------------
Capital Contributions from Parent - 50,000
Change in Advances to/from Affiliates, Net 42,170 (17,550)
Retirement of Long-term Debt (111,020) (35,000)
Issuance of Long-term Debt 83,129 -
Reacquired Preferred Stock (3) -
Dividends Paid on Common Stock (17,500) (7,500)
Dividends Paid on Cumulative Preferred Stock (106) (106)
--------- --------
Net Cash Flows Used For Financing Activities (3,330) (10,156)
--------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 105 (1,044)
Cash and Cash Equivalents at Beginning of Period 3,738 9,543
--------- --------
Cash and Cash Equivalents at End of Period $3,843 $8,499
========= ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $17,600,000 and $24,107,000 and for income taxes was $(2,695,000)
and $8,975,000 in 2004 and 2003, respectively.
There was a non-cash distribution of $548,000 in preferred shares in AEMT, Inc. to PSO's Parent Company in 2003.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to PSO's financial statements are combined with the notes to financial
statements for other subsidiary registrants. Listed below are the notes that
apply to PSO. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
------------------------------------------------
Results of Operations
- ---------------------
Net Income decreased $7 million for 2004 year-to-date, but increased $7 million
for the second quarter. The year-to-date decrease is due in large part to a
decline in margins from risk management activities and the $9 million (net of
tax) Cumulative Effect of Accounting Changes recorded in 2003. For the quarter,
the decreased risk management margins were more than offset by increased retail
revenues and a purchased power refund.
Fluctuations occurring in the retail portion of fuel and purchased power expense
generally do not impact operating income, as they are offset in revenues and/or
operations expense due to the functioning of the fuel adjustment clauses in the
states in which we serve.
Second Quarter 2004 Compared to Second Quarter 2003
- ---------------------------------------------------
Operating Income
- ----------------
Operating Income increased by $6 million primarily due to:
o Increased retail base revenues of $8 million due to an increased number of
customers and their average usage, offset in part by milder weather.
o Decreased fuel expense of 10% due both to lower KWH generation of 4% and
lower cost per KWH of 6%.
o Decreased purchased power of 88% due mainly to a refund of capacity payments
for prior periods of $8.6 million. Additionally, KWH purchases declined
17% and the cost per KWH declined by 38%.
The increase in Operating Income was partially offset by:
o Decreased retained margins from off-system sales of $2 million due to mainly
to decreased realization of off-system sales.
o Decreased margins from risk management activities of $6 million.
o Increased Other Operation expenses of $2 million primarily related to
transmission expense.
o Increased Maintenance expense of $5 million resulting from $3 million of
overhead line expense primarily related to storm damage, as well as
scheduled power plant maintenance.
o Increased Taxes Other Than Income Taxes of $2 million due primarily to
higher property taxes.
Other Impacts on Earnings
- -------------------------
Interest Charges decreased $2 million as a result of refinancing higher interest
rate debt and trust preferred securities with lower cost debt and trust
preferred securities.
Minority Interest of $1 million is a result of consolidating Sabine Mining
Company (Sabine) effective July 1, 2003, due to implementation of FIN 46. We now
record the depreciation, interest and other operating expenses of Sabine and
eliminate Sabine's revenues against our fuel expenses. While there was no effect
to net income as a result of consolidation, some individual income statement
captions were affected.
Income Taxes
The effective tax rates for the second quarter of 2004 and 2003 were 33.2% and
32.9%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The effective tax rates remained
relatively flat for the comparative period.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating Income
- ----------------
Operating Income was virtually unchanged but negatively impacted by:
o Decreased retained margins from off-system sales of $2 million due mainly to
decreased realization of off-system sales.
o Decreased margins from risk management activities of $9 million.
o Increased Other Operation expenses of $8 million primarily related to a
prior year true up for OATT transmission recorded in 2004 resulting from
revised data from ERCOT for the years 2001-2003 offset in part by lower
administrative expenses.
o Increased Maintenance expense of $8 million primarily related to scheduled
power plant maintenance, as well as increased overhead line maintenance,
partly due to increased storm damage.
o Increased Depreciation and Amortization expense of $4 million due
primarily to the restoration in 2003 of a regulatory asset related to the
recovery of fuel related cost in Arkansas.
o Increased Taxes Other Than Income Taxes of $3 million due primarily to
higher property taxes and state and local franchise taxes.
Operating Income was positively affected by:
o Increased retail base revenues of $12 million, 5%, due to an increased
number of customers and their average usage, offset in part by milder
weather. Cooling and heating degree-days decreased 4%.
o Total purchased power decreased by 66% due mainly to a refund of capacity
payments for prior periods of $8.6 million. Additionally, KWH purchases
declined 19% and the cost per KWH declined 20%.
Other Impacts on Earnings
- -------------------------
Interest Charges decreased $3 million as a result of refinancing higher interest
rate debt and trust preferred securities with lower cost debt and trust
preferred securities.
Minority Interest of $2 million is a result of consolidating Sabine effective
July 1, 2003, due to implementation of FIN 46. We now record the depreciation,
interest and other operating expenses of Sabine and eliminate Sabine's revenues
against our fuel expenses. While there was no effect to net income as a result
of consolidation, some individual income statement captions were affected.
The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 and EITF 02-3 in 2003.
Income Taxes
- ------------
The effective tax rates for the first six months of 2004 and 2003 were 29.3% and
33.1%, respectively. The difference in the effective income tax rate and the
federal statutory rate of 35% is due to permanent differences, amortization of
investment tax credits and state income taxes. The decrease in the effective tax
rate is primarily due to permanent differences relating to book depletion and
Medicare subsidy.
Financial Condition
- -------------------
Credit Ratings
- --------------
The rating agencies currently have us on stable outlook. Our first mortgage
bonds were upgraded by S&P to A- due to a change in methodology at the agency.
Current ratings are as follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 A- A
Senior Unsecured Debt Baa1 BBB A-
Cash Flow
- ---------
Cash flows for the six months ended June 30, 2004 and 2003 were as follows:
2004 2003
---- ----
Cash and cash equivalents at beginning of period $5,676 $-
-------- --------
Cash flows from (used for):
Operating activities 113,340 114,574
Investing activities (57,360) (63,575)
Financing activities (50,054) (43,674)
-------- --------
Net increase in cash and cash equivalents 5,926 7,325
-------- --------
Cash and cash equivalents at end of period $11,602 $7,325
======== ========
Operating Activities
- --------------------
Cash Flows From Operating Activities were $113 million primarily due to Net
Income, Accounts Payable, Fuel Recovery and Taxes Accrued offset in part by
Accounts Receivable, Net and Other Assets and Liabilities.
Investing Activities
- --------------------
Cash Used for Investing Activities was primarily related to construction
projects for improved transmission and distribution service reliability.
Financing Activities
- --------------------
Cash Flows Used For Financing Activities through long-term debt issuances and
advances from affiliates were used to replace higher interest rate long-term
debt with lower interest rate long-term debt.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first six months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase Contracts $53,500 Variable 2019
Installment Purchase Contracts 41,135 Variable 2011
Financing Obligations 14,226 5.77 2024
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase Contracts $53,500 7.60 2019
Installment Purchase Contracts 12,290 6.90 2004
Installment Purchase Contracts 12,170 6.00 2008
Installment Purchase Contracts 17,125 8.20 2011
First Mortgage Bonds 80,000 6.875 2025
First Mortgage Bonds 40,000 7.75 2004
Notes Payable 3,415 4.47 2011
Notes Payable 1,500 Variable 2008
Significant Factors
- -------------------
See the "Registrant Subsidiaries' Combined Management's Discussion and Analysis"
section beginning on page M-1 for additional discussion of factors relevant to
us.
Critical Accounting Estimates
- -----------------------------
See "Critical Accounting Policies" in "Registrants' Combined Management's
Discussion and Analysis" in the 2003 Annual Report for a discussion of the
estimates and judgments required for revenue recognition, the valuation of
long-lived assets, the accounting for pension benefits and the impact of new
accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------
Market Risks
- ------------
Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Quantitative
and Qualitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.
MTM Risk Management Contract Net Assets
- ---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2004
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2003 $16,606
(Gain) Loss from Contracts Realized/Settled During the Period (a) (3,571)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 73
Change in Fair Value Due to Valuation Methodology Changes (d) 62
Changes in Fair Value of Risk Management Contracts (e) (1,720)
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f) (7,027)
--------
Total MTM Risk Management Contract Net Assets 4,423
Net Cash Flow Hedge Contracts (g) (1,309)
--------
Total MTM Risk Management Contract Net Assets at June 30, 2004 $3,114
========
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized risk management contracts and related derivatives
that settled during 2004 that were entered into prior to 2004.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long- term contracts entered
into with customers during 2004. The fair value is calculated as of
the execution of the contract. Most of the fair value comes from
longer term fixed price contracts with customers that seek to limit
their risk against fluctuating energy prices. The contract prices
are valued against market curves associated with the delivery
location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and
unexpired option contracts that were entered into in 2004.
(d) "Change in Fair Value Due to Valuation Methodology Changes"
represents the impact of AEP changes in methodology in regards to
credit reserves on forward contracts.
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- --- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(446) $44 $(1) $142 $- $- $(261)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 1,729 936 186 - - - 2,851
Prices Based on Models and Other
Valuation Methods (b) (181) 727 (53) 141 301 898 1,833
------- ------- ----- ----- ----- ----- -------
Total $1,102 $1,707 $132 $283 $301 $898 $4,423
======= ======= ===== ===== ===== ===== =======
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" is in absence of
pricing information from external sources, modeled information is
derived using valuation models developed by the reporting entity,
reflecting when appropriate, option pricing theory, discounted cash
flow concepts, valuation adjustments, etc. and may require projection
of prices for underlying commodities beyond the period that prices are
available from third-party sources. In addition, where external pricing
information or market liquidity are limited, such valuations are
classified as modeled. The determination of the point at which a market
is no longer liquid for placing it in the modeled category varies by
market.
(c) Amounts exclude Cash Flow Hedges.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
- --------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations on
the future cash flows from assets. We do not hedge all commodity price risk.
We employ cash flow hedges to mitigate changes in interest rates or fair values
on short and long-term debt when management deems it necessary. We do not hedge
all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. Under SFAS 133 only contracts designated as cash
flow hedges are recorded in AOCI, therefore, economic hedge contracts which are
not designated as cash flow hedges are required to be marked-to-market and are
included in the previous risk management tables. In accordance with GAAP, all
amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
For the Six Months Ended June 30, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $184
Changes in Fair Value (a) (500)
Reclassifications from AOCI to Net Income (b) (118)
-------
Ending Balance June 30, 2004 $(434)
======
(a) "Changes in Fair Value" shows changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of related
income taxes.
(b) "Reclassifications from AOCI to Net Income" represents gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $278 thousand loss.
Credit Risk
- -----------
Our counterparty credit quality and exposure is generally consistent with that
of AEP.
VaR Associated with Risk Management Contracts
- ---------------------------------------------
The following table shows the end, high, average, and low market risk as
measured by VaR for the period indicated:
Six Months Ended Twelve Months Ended
June 30, 2004 December 31, 2003
---------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$115 $260 $129 $65 $304 $1,182 $495 $118
VaR Associated with Debt Outstanding
- ------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $40 million and $57 million at June 30, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2004 and 2003
(Unaudited)
Three Months Ended Six Months Ended
------------------- -------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- -------------------------------------------------------
Electric Generation, Transmission and Distribution $251,230 $263,907 $465,179 $487,521
Sales to AEP Affiliates 17,498 17,399 39,709 49,063
------------ ------------ ----------- ----------
TOTAL 268,728 281,306 504,888 536,584
----------- ----------- ---------- ---------
OPERATING EXPENSES
- -------------------------------------------------------
Fuel for Electric Generation 94,245 104,979 183,068 204,618
Purchased Electricity for Resale (4,008) 10,365 1,926 22,932
Purchased Electricity from AEP Affiliates 7,113 14,841 14,420 25,651
Other Operation 44,273 42,383 94,540 86,611
Maintenance 24,011 18,931 39,659 31,748
Depreciation and Amortization 31,979 30,868 63,264 58,903
Taxes Other Than Income Taxes 15,148 13,168 31,715 29,041
Income Taxes 14,439 10,183 14,570 15,448
--------- --------- --------- ---------
TOTAL 227,200 245,718 443,162 474,952
--------- --------- --------- ---------
OPERATING INCOME 41,528 35,588 61,726 61,632
Nonoperating Income 792 475 2,195 1,347
Nonoperating Expenses 1,240 355 2,066 876
Nonoperating Income Tax (Credit) (541) (105) (897) (55)
Interest Charges 12,862 15,223 28,090 31,077
Minority Interest 813 - 1,694 -
--------- --------- --------- ---------
Income Before Cumulative Effect of Accounting Changes 27,946 20,590 32,968 31,081
Cumulative Effect of Accounting Changes (Net of Tax) - - - 8,517
--------- --------- --------- ---------
NET INCOME 27,946 20,590 32,968 39,598
Preferred Stock Dividend Requirements 58 58 115 115
--------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $27,888 $20,532 $32,853 $39,483
========= ========= ========= =========
The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
DECEMBER 31, 2002 $135,660 $245,003 $334,789 $(53,683) $661,769
Common Stock Dividends (36,396) (36,396)
Preferred Stock Dividends (115) (115)
---------
TOTAL 625,258
---------
COMPREHENSIVE INCOME
- ------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,004) (1,004)
NET INCOME 39,598 39,598
---------
TOTAL COMPREHENSIVE INCOME 38,594
--------- --------- --------- --------- ---------
JUNE 30, 2003 $135,660 $245,003 $337,876 $(54,687) $663,852
========= ========= ========= ========= =========
DECEMBER 31, 2003 $135,660 $245,003 $359,907 $(43,910) $696,660
Common Stock Dividends (30,000) (30,000)
Preferred Stock Dividends (115) (115)
---------
TOTAL 666,545
---------
COMPREHENSIVE INCOME
- ------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (618) (618)
Minimum Pension Liability 23,066 23,066
NET INCOME 32,968 32,968
---------
TOTAL COMPREHENSIVE INCOME 55,416
--------- --------- --------- --------- ---------
JUNE 30, 2004 $135,660 $245,003 $362,760 $(21,462) $721,961
========= ========= ========= ========= =========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -----------------------------------------------------
Production $1,657,785 $1,622,498
Transmission 629,662 615,158
Distribution 1,097,960 1,078,368
General 445,896 423,427
Construction Work in Progress 31,100 60,009
----------- -----------
TOTAL 3,862,403 3,799,460
Accumulated Depreciation and Amortization 1,673,188 1,617,846
----------- -----------
TOTAL - NET 2,189,215 2,181,614
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- -----------------------------------------------------
Non-Utility Property, Net 4,050 3,808
Other Investments 4,710 4,710
----------- -----------
TOTAL 8,760 8,518
----------- -----------
CURRENT ASSETS
- -----------------------------------------------------
Cash and Cash Equivalents 11,602 5,676
Other Cash Deposits 5,245 6,048
Advances to Affiliates - 66,476
Accounts Receivable:
Customers 42,103 41,474
Affiliated Companies 17,484 10,394
Miscellaneous 4,018 4,682
Allowance for Uncollectible Accounts (4,675) (2,093)
Fuel Inventory 59,898 63,881
Materials and Supplies 35,675 33,775
Regulatory Asset for Under-recovered Fuel Costs 4,822 11,394
Risk Management Assets 7,734 19,715
Margin Deposits 437 5,123
Prepayments and Other 18,252 19,078
----------- -----------
TOTAL 202,595 285,623
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- -----------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 5,281 3,235
Unamortized Loss on Reacquired Debt 22,161 19,331
Minimum Pension Liability 35,486 -
Other 15,195 15,859
Long-term Risk Management Assets 4,512 12,178
Deferred Charges 71,580 55,605
----------- -----------
TOTAL 154,215 106,208
----------- -----------
TOTAL ASSETS $2,554,785 $2,581,963
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
June 30, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- ---------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares $135,660 $135,660
Paid-in Capital 245,003 245,003
Retained Earnings 362,760 359,907
Accumulated Other Comprehensive Income (Loss) (21,462) (43,910)
----------- -----------
Total Common Shareholder's Equity 721,961 696,660
Cumulative Preferred Stock Not Subject to Mandatory Redemption 4,700 4,700
----------- -----------
Total Shareholder's Equity 726,661 701,360
Long-term Debt 763,486 741,594
----------- -----------
TOTAL 1,490,147 1,442,954
----------- -----------
Minority Interest 1,280 1,367
----------- -----------
CURRENT LIABILITIES
- ---------------------------------------------------------------
Long-term Debt Due Within One Year 10,244 142,714
Advances from Affiliates 26,918 -
Accounts Payable:
General 43,740 37,646
Affiliated Companies 32,558 35,138
Customer Deposits 26,731 24,260
Taxes Accrued 75,180 28,691
Interest Accrued 11,848 16,852
Risk Management Liabilities 6,239 11,361
Obligations Under Capital Leases 3,420 3,159
Regulatory Liability for Over-recovered Fuel 6,204 4,178
Other 32,867 53,753
----------- -----------
TOTAL 275,949 357,752
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ---------------------------------------------------------------
Deferred Income Taxes 358,813 349,064
Long-term Risk Management Liabilities 2,893 4,667
Reclamation Reserve 7,632 16,512
Regulatory Liabilities:
Asset Removal Costs 243,305 236,409
Deferred Investment Tax Credits 37,701 39,864
Excess Earnings 2,600 2,600
Other 7,870 18,779
Asset Retirement Obligations 26,665 8,429
Obligations Under Capital Leases 18,139 18,383
Deferred Credits and Other 81,791 85,183
----------- -----------
TOTAL 787,409 779,890
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $2,554,785 $2,581,963
=========== ===========
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ---------------------------------------------------
Net Income $32,968 $39,598
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (8,517)
Depreciation and Amortization 63,264 58,903
Deferred Income Taxes (4,519) 2,413
Deferred Investment Tax Credits (2,163) (2,163)
Deferred Property Taxes (19,375) (18,630)
Mark-to-Market of Risk Management Contracts 12,181 (13,945)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (4,473) 9,696
Fuel, Materials and Supplies 2,083 7,445
Accounts Payable 3,514 (12,349)
Taxes Accrued 46,489 23,792
Fuel Recovery 8,598 (14,148)
Change in Other Assets (6,049) 10,887
Change in Other Liabilities (19,178) 31,592
--------- --------
Net Cash Flows From Operating Activities 113,340 114,574
--------- --------
INVESTING ACTIVITIES
- ---------------------------------------------------
Construction Expenditures (60,479) (62,883)
Proceeds from Sale of Assets and Other 2,316 414
Change in Other Cash Deposits, Net 803 (1,106)
--------- --------
Net Cash Flows Used For Investing Activities (57,360) (63,575)
--------- --------
FINANCING ACTIVITIES
- ---------------------------------------------------
Issuance of Long-term Debt 106,667 143,041
Retirement of Long-term Debt (220,000) (56,020)
Change in Advances to/from Affiliates, Net 93,394 (94,184)
Dividends Paid on Common Stock (30,000) (36,396)
Dividends Paid on Cumulative Preferred Stock (115) (115)
--------- --------
Net Cash Flows Used For Financing Activities (50,054) (43,674)
--------- --------
Net Increase in Cash and Cash Equivalents 5,926 7,325
Cash and Cash Equivalents at Beginning of Period 5,676 -
--------- --------
Cash and Cash Equivalents at End of Period $11,602 $7,325
========= ========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $29,841,000 and $27,741,000 and for income taxes was $3,220,000 and
$17,062,000 in 2004 and 2003, respectively.
See Notes to Financial Statements of Registrant Subsidiaries beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
-----------------------------------------------------------------
The notes to SWEPCo's consolidated financial statements are combined with the
notes to financial statements for other subsidiary registrants. Listed below
are the notes that apply to SWEPCo. The footnotes begin on page L-1.
Footnote
Reference
---------
Significant Accounting Matters Note 1
New Accounting Pronouncements Note 2
Rate Matters Note 3
Customer Choice and Industry Restructuring Note 4
Commitments and Contingencies Note 5
Guarantees Note 6
Benefit Plans Note 8
Business Segments Note 9
Financing Activities Note 10
NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
--------------------------------------------------------
The notes to financial statements that follow are a combined presentation for
AEP's registrant subsidiaries. The following list indicates the registrants to
which the footnotes apply:
1. Significant Accounting Matters AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
2. New Accounting Pronouncements AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
3. Rate Matters APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
4. Customer Choice and APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC
Industry Restructuring
5. Commitments and Contingencies AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
6. Guarantees AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
7. Dispositions and Assets Held TCC
for Sale
8. Benefit Plans APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
9. Business Segments AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
10. Financing Activities AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
1. SIGNIFICANT ACCOUNTING MATTERS
------------------------------
General
- -------
The accompanying unaudited interim financial statements should be read
in conjunction with the 2003 Annual Report as incorporated in and filed
with our 2003 Form 10-K.
In the opinion of management, the unaudited interim financial statements
reflect all normal and recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for
interim periods.
Components of Accumulated Other Comprehensive Income (Loss)
- -----------------------------------------------------------
Accumulated Other Comprehensive Income (Loss) is included on the balance
sheet in the equity section. The components of Accumulated Other
Comprehensive Income (Loss) for AEP registrant subsidiaries is shown in
the following table.
June 30, December 31,
Components 2004 2003
----------- ---- ----
(in thousands)
Cash Flow Hedges:
APCo $(6,031) $(1,569)
CSPCo (2,195) 202
I&M (2,756) 222
KPCo (542) 420
OPCo (3,345) (103)
PSO (370) 156
SWEPCo (434) 184
TCC (11,242) (1,828)
TNC (3,765) (601)
Minimum Pension Liability:
APCo $(50,519) $(50,519)
CSPCo (46,529) (46,529)
I&M (25,328) (25,328)
KPCo (6,633) (6,633)
OPCo (52,646) (48,704)
PSO (43,998) (43,998)
SWEPCo (21,027) (44,094)
TCC (62,511) (60,044)
TNC (26,117) (26,117)
During the first quarter of 2004, SWEPCo reclassified $23 million from
Accumulated Other Comprehensive Income (Loss) related to minimum pension
liability to Regulatory Assets ($35 million) and Deferred Income Taxes
($12 million) as a result of authoritative letters issued by the FERC
and the Arkansas and Louisiana commissions.
Accounting for Asset Retirement Obligations
- -------------------------------------------
We implemented SFAS 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003, which requires entities to record a liability
at fair value for any legal obligations for asset retirements in the
period incurred. Upon establishment of a legal liability, SFAS 143
requires a corresponding asset to be established which will be
depreciated over its useful life.
The following is a reconciliation of beginning and ending aggregate
carrying amounts of asset retirement obligations by registrant
subsidiary following the adoption of SFAS 143:
Balance At Balance at
January 1, Liabilities June 30,
2004 Accretion Incurred 2004
---------- --------- ----------- ----------
(in millions)
AEGCo (a) $1.1 $0.1 $- $1.2
APCo (a) 21.7 0.9 - 22.6
CSPCo (a) 8.7 0.4 - 9.1
I&M (b) 553.2 19.6 - 572.8
OPCo (a) 42.7 1.6 - 44.3
SWEPCo (d) 8.4 0.6 17.7 26.7
TCC (c) 218.8 8.2 - 227.0
(a) Consists of asset retirement obligations related to ash ponds.
(b) Consists of asset retirement obligations related to ash ponds
($1.2 million at June 30, 2004) and nuclear decommissioning costs
for the Cook Plant ($571.6 million at June 30, 2004).
(c) Consists of asset retirement obligations related to nuclear
decommissioning costs for STP included in Liabilities Held for Sale
- Texas Generation Plants on TCC's Consolidated Balance Sheets.
(d) Consists of asset retirement obligations related to Sabine Mining and
Dolet Hills.
Accretion expense is included in Other Operation expense in the
respective income statements of the individual subsidiary registrants.
As of June 30, 2004 and December 31 2003, the fair value of assets that
are legally restricted for purposes of settling the nuclear
decommissioning liabilities totaled $885 million ($754 million for I&M
and $131 million for TCC) and $845 million ($720 million for I&M and
$125 million for TCC), respectively, recorded in Nuclear Decommissioning
and Spent Nuclear Fuel Disposal Trust Funds on I&M's Consolidated
Balance Sheets and in Assets Held for Sale-Texas Generation Plants on
TCC's Consolidated Balance Sheets.
Reclassification
- ----------------
Certain prior period financial statement items have been reclassified to
conform to current period presentation. Such reclassifications had no
impact on previously reported Net Income (Loss).
2. NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------
FIN 46 (revised December 2003)"Consolidation of Variable Interest Entities"
FIN 46R
- ---------------------------------------------------------------------------
We implemented FIN 46R, "Consolidation of Variable Interest Entities,"
effective March 31, 2004 with no material impact to our financial
statements. FIN 46R is a revision to FIN 46 which interprets the
application of Accounting Research Bulletin No. 51, "Consolidated
Financial Statements," to certain entities in which equity investors do
not have the characteristics of a controlling financial interest or do
not have sufficient equity at risk for the entity to finance its
activities without additional subordinated financial support from other
parties.
FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug Improvement and Modernization Act
of 2003
- ----------------------------------------------------------------------------
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC implemented FASB
Staff Position (FSP) FAS 106-2, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization
Act of 2003," effective April 1, 2004, retroactive to January 1, 2004.
The new disclosure standard provides authoritative guidance on the
accounting for any effects of the Medicare prescription drug subsidy
under the Act. It replaces the earlier FSP FAS 106-1, under which APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC previously elected to
defer accounting for any effects of the Act until the FASB issued
authoritative guidance on the accounting for the Medicare subsidy.
Under FSP FAS 106-2, the current portion of the Medicare subsidy for
employers who qualify for the tax-free subsidy is a reduction of ongoing
FAS 106 cost, while the retroactive portion is an actuarial gain to be
amortized over the average remaining service period of active employees,
to the extent that the gain exceeds FAS 106's 10 percent corridor. The
Medicare subsidy reduced the FAS 106 accumulated postretirement benefit
obligation (APBO) related to benefits attributed to past service by $202
million. The tax-free subsidy reduced AEP's second quarter net periodic
postretirement benefit cost by a total of $7 million, including $3
million of amortization of the actuarial gain, $1 million of reduced
service cost, and $3 million of reduced interest cost on the APBO. After
adjustment to capitalization of employee benefits costs as of a cost of
construction projects, $5 million of this tax-free cost reduction
remained to increase AEP's second quarter net income.
The following table provides the reduction in the net periodic
postretirement benefit cost for the second quarter of 2004 for the AEP
registrant subsidiaries:
Postretirement Benefit
Cost Reduction
----------------------
(in thousands)
APCo $815
CSPCo 413
I&M 632
KPCo 121
OPCo 720
PSO 281
SWEPCo 291
TCC 327
TNC 143
The effect of implementing FSP FAS 106-2 on AEP for the first quarter of 2004
is as follows:
Three Months Ended March, 31, 2004 Earnings in Millions Earnings Per Share
---------------------------------- -------------------- ------------------
Originally Reported $278 $0.70
Effect of Medicare Subsidy 5 0.02
----- ------
Restated $283 $0.72
===== =====
The effect of implementing FSP FAS 106-2 by the following AEP registrant
subsidiaries for the first quarter of 2004 is as follows:
Originally Effect of
Reported Net Medicare Restated
Income (Loss) Subsidy Net Income (Loss)
------------- --------- -----------------
(in thousands)
APCo $64,521 $815 $65,336
CSPCo 44,705 413 45,118
I&M 42,376 632 43,008
KPCo 11,490 121 11,611
OPCo 79,444 720 80,164
PSO (9,284) 281 (9,003)
SWEPCo 4,730 291 5,021
TCC 29,077 327 29,404
TNC 12,953 143 13,096
Future Accounting Changes
- -------------------------
The FASB's standard-setting process is ongoing and until new standards
have been finalized and issued by FASB, we cannot determine the impact
on the reporting of our operations that may result from any such future
changes. The FASB is currently working on several projects including
discontinued operations, business combinations, liabilities and equity,
revenue recognition, accounting for equity-based compensation, pension
plans, asset retirement obligations, earnings per share calculations,
fair value measurements, and related tax impacts. We also expect to see
more projects as a result of the FASB's desire to converge International
Accounting Standards with those generally accepted in the United States
of America. The ultimate pronouncements resulting from these and future
projects could have an impact on our future results of operations and
financial position.
3. RATE MATTERS
------------
As discussed in our 2003 Annual Report, rate and regulatory proceedings
at the FERC and at several state commissions are ongoing. The Rate
Matters note within our 2003 Annual Report should be read in conjunction
with this report in order to gain a complete understanding of material
rate matters still pending, without significant changes since year-end.
The following sections discuss current activities.
TNC Fuel Reconciliation - Affecting TNC
- ----------------------------------------
In 2002, TNC filed with the PUCT to reconcile fuel costs, requesting to
defer any unrecovered portion applicable to retail sales within its
ERCOT service area for inclusion in the 2004 true-up proceeding. This
reconciliation for the period from July 2000 through December 2001 will
be the final fuel reconciliation for TNC's ERCOT service territory.
In March 2003, the ALJ in this proceeding filed a Proposal for Decision
(PFD) with a recommendation that TNC's under-recovered retail fuel
balance be reduced. In March 2003, TNC established a reserve of $13
million based on the recommendations in the PFD. In May 2003, the PUCT
reversed the ALJ on certain matters and remanded TNC's final fuel
reconciliation to the ALJ to consider two issues: (1) the sharing of
off-system sales margins from AEP's trading activities with customers
for five years per the PUCT's interpretation of the Texas AEP/CSW merger
settlement and (2) the inclusion of January 2002 fuel factor revenues
and associated costs in the determination of the under-recovery. The
PUCT proposed that the sharing of off-system sales margins for periods
beyond the termination of the fuel factor should be recognized in the
final fuel reconciliation proceeding. This would result in the sharing
of margins for an additional three and one-half years after the end of
the Texas ERCOT fuel factor. While management believes that the Texas
merger settlement only provided for sharing of margins during the period
fuel and generation costs were regulated by the PUCT, an additional
provision of $10 million was recorded in December 2003.
In December 2003, the ALJ issued a PFD in the remand phase of the TNC
fuel reconciliation recommending additional disallowances for the two
remand issues. TNC filed responses to the PFD and the PUCT announced a
final ruling in the fuel reconciliation proceeding in January 2004
accepting the PFD. TNC received a written order in March 2004 and
increased the reserve by $1.5 million. In March 2004, various parties,
including TNC, requested a rehearing of the PUCT's ruling. In May 2004,
the PUCT reversed its position on the inclusion of MTM amounts in the
allocation of system sales margins and remanded the case to the ALJ. As
a result, TNC recorded an additional provision of $12 million in the
second quarter of 2004 resulting in an over-recovery balance of $7
million at June 30, 2004.
On July 2, 2004, the parties to the MTM remand proceeding filed a
"Stipulation of Fact." All parties agreed to the amount of the remanded
issue. If the amounts included in the "Stipulation of Fact" are
approved, the over-recovery balance will be reduced to $4 million. We
expect the PUCT to issue its final order in this proceeding in August
2004.
TCC Fuel Reconciliation - Affecting TCC
- -----------------------------------------
In 2002, TCC filed its final fuel reconciliation with the PUCT to
reconcile fuel costs to be included in its deferred over-recovery
balance in the 2004 true-up proceeding. This reconciliation covers the
period from July 1998 through December 2001.
Based on the PUCT ruling in the TNC proceeding relating to similar
issues, TCC established a reserve for potential adverse rulings of $81
million during 2003. On February 3, 2004, the ALJ issued a PFD
recommending that the PUCT disallow $140 million in eligible fuel costs
including some new items not considered in the TNC case, and other items
considered but not disallowed in the TNC ruling. Based on an analysis of
the ALJ's recommendations, TCC established an additional reserve of $13
million during the first quarter of 2004. In May 2004, the PUCT accepted
most of the ALJ's recommendations. The PUCT rejected the ALJ's
recommendation to impute capacity to certain energy-only purchased power
contracts and remanded the issue to the ALJ to determine if any energy-
only purchased power contracts during the reconciliation period include
a capacity component that is not recoverable in fuel revenues. Hearings
are scheduled in October 2004 for the remand issue. As a result of the
PUCT's acceptance of the ALJ's recommendations and the PUCT's remand
decision in the TNC case regarding the inclusion of MTM amounts in the
allocation of AEP's net system sales margins, TCC increased its
provision by $47 million in the second quarter of 2004. The
over-recovery balance and the provisions total $210 million including
interest at June 30, 2004. At this time, management is unable to predict
the outcome of this proceeding. An adverse ruling from the PUCT,
disallowing amounts in excess of the established reserve, could have a
material impact on future results of operations and cash flows.
Additional information regarding the 2004 true-up proceeding for TCC can
be found in Note 4 "Customer Choice and Industry Restructuring."
SWEPCo Texas Fuel Reconciliation - Affecting SWEPCo
- ---------------------------------------------------
In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in the
SPP. This reconciliation covers the period from January 2000 through
December 2002. During the reconciliation period, SWEPCo incurred $435
million of Texas retail eligible fuel expense. In November 2003,
intervenors and the PUCT Staff recommended fuel cost disallowances of
more than $30 million. In December 2003, SWEPCo agreed to a settlement
in principle with all parties in the fuel reconciliation. The settlement
provides for a disallowance in fuel costs of $8 million which was
recorded in December 2003. In April 2004, the PUCT approved the
settlement.
TCC Rate Case - Affecting TCC
- -----------------------------
On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates
should not be reduced. Other municipalities served by TCC passed similar
rate review resolutions. In Texas, municipalities have original
jurisdiction over rates of electric utilities within their municipal
limits. Under Texas law, TCC must provide support for its rates to the
municipalities. TCC filed the requested support for its rates based on a
test year ending June 30, 2003 with all of its municipalities and the
PUCT on November 3, 2003. TCC's proposal would decrease its wholesale
transmission rates by $2 million or 2.5% and increase its retail energy
delivery rates by $69 million or 19.2%. In February 2004, eight
intervening parties and the PUCT Staff filed testimony recommending
reductions to TCC's requested $67 million rate increase. The
recommendations ranged from a decrease in existing rates of
approximately $100 million to an increase in TCC's current rates of
approximately $27 million. Hearings were held in March 2004. In May
2004, TCC agreed to a non-unanimous settlement on cost of capital
including capital structure and return on equity with all but two
parties in the proceeding. TCC agreed that the return on equity should
be established at 10.125% based upon a capital structure with 40% equity
resulting in a weighted cost of capital of 7.475%. The settlement and
other agreed adjustments reduced TCC's rate request to $41 million. The
ALJs that heard the case issued their recommendations on July 2, 2004
including a recommendation to approve the cost of capital settlement.
The ALJs recommended that an issue related to the allocation of
consolidated tax savings to the transmission and distribution utility be
remanded for additional evidence. On July 15, 2004, the PUCT agreed to
remand this issue to the ALJs. In addition, the PUCT ordered TCC to
calculate its revenue requirements based upon the recommendations of the
ALJs. On July 21, 2004, TCC filed its revenue requirements based upon
the recommendations of the ALJs. According to TCC's calculations, the ALJs'
recommendations reduce TCC's existing rates by a range of $33 million to $43
million depending on the final resolution of the amount of consolidation tax
savings. TCC filed exceptions to the ALJs' recommendations on July 21, 2004.
The PUCT is expected to issue its decision in September 2004. Management is
unable to predict the ultimate effect of this proceeding on TCC's rates,
revenues, results of operations, cash flows and financial condition.
Louisiana Compliance Filing - Affecting SWEPCo
- -----------------------------------------------
In October 2002, SWEPCo filed with the Louisiana Public Service
Commission (LPSC) detailed financial information typically utilized in a
revenue requirement filing, including a jurisdictional cost of service.
This filing was required by the LPSC as a result of their order
approving the merger between AEP and CSW. The LPSC's merger order also
provides that SWEPCo's base rates are capped at the present level
through mid-2005. In April 2004, SWEPCo filed updated financial
information with a test year ending December 31, 2003 as required by the
LPSC. Both filings indicated that SWEPCo's current rates should not be
reduced. If, after review of the updated information, the LPSC disagrees
with our conclusion, they could order SWEPCo to file all documents for a
full cost of service revenue requirement review in order to determine
whether SWEPCo's capped rates should be reduced, which if a rate
reduction is ordered, would adversely impact results of operations and
cash flows.
PSO Fuel and Purchased Power - Affecting PSO
- --------------------------------------------
In 2002, PSO experienced a $44 million under-recovery of fuel costs
resulting from a reallocation among AEP West companies of purchased
power costs for periods prior to January 1, 2002. In July 2003, PSO
filed with the Corporation Commission of the State of Oklahoma (OCC)
seeking to recover these costs over a period of 18 months. In August
2003, the OCC Staff filed testimony recommending PSO be granted recovery
of $42.4 million over three years. In September 2003, the OCC expanded
the case to include a full review of PSO's 2001 fuel and purchased power
practices. PSO filed its testimony in February 2004. An intervenor and
the OCC Staff filed testimony in April 2004. The intervenor suggested
$8.8 million related to the 2002 reallocation not be recovered from
customers. The Attorney General of Oklahoma also filed a statement of
position, indicating allocated trading margins between and among AEP
operating companies were inconsistent with the FERC-approved Operating
Agreement and System Integration Agreement and could more than offset
the $44 million 2002 reallocation. The intervenor and the OCC Staff also
believed trading margins were allocated incorrectly and that a
reallocation by the intervenors of such margins would reduce PSO's
recoverable fuel by approximately $6.8 million for 2000 and $10.7
million for 2001, while under the OCC Staff method, the amount for 2001
would be $8.8 million. The intervenor and the OCC Staff also recommend
recalculation of fuel for years subsequent to 2001 using the same
methods. At a June 2004 prehearing conference, PSO questioned whether
the issues in dispute were the jurisdiction of the OCC or the FERC
because they relate to the FERC-approved agreements. As a result, the
ALJ ordered that the jurisdictional issue be briefed by the parties.
PSO is required to file its brief by September 1, 2004. Subject to
decisions by the OCC as to jurisdiction, a hearing date has been set
for January 2005. Management believes that fuel costs have been
prudently incurred consistent with OCC rules, and that the allocation of
trading margins pursuant to the agreements is correct. If the OCC
determines, as a result of the review that a portion of PSO's fuel and
purchased power costs should not be recovered, there will be an adverse
effect on PSO's results of operations, cash flows and possibly financial
condition.
RTO Formation/Integration - Affecting APCo, CSPCo, I&M, KPCo, and OPCo
- ----------------------------------------------------------------------
With FERC approval, AEP East companies have been deferring costs
incurred under FERC orders to form an RTO (the Alliance RTO) or join an
existing RTO (PJM). In July 2003, the FERC issued an order approving our
continued deferral of both our Alliance formation costs and our PJM
integration costs including the deferral of a carrying charge. The AEP
East companies have deferred approximately $33 million of RTO formation
and integration costs and related carrying charges through June 30,
2004. Amounts per company are as follows:
Company (in millions)
------- -------------
APCo $9.4
CSPCo 3.9
I&M 7.2
KPCo 2.2
OPCo 10.3
As a result of the subsequent delay in the integration of AEP's East
transmission system into PJM, FERC declined to rule, in its July 2003
order, on our request to transfer the deferrals to regulatory assets,
and to maintain the deferrals until such time as the costs can be
recovered from all users of AEP's East transmission system. The AEP East
companies plan to apply for permission to transfer the deferred
formation/integration costs to a regulatory asset prior to integration
with PJM.
In its July 2003 order, FERC indicated that it would review the deferred
costs at the time they are transferred to a regulatory asset account and
scheduled for amortization and recovery in the open access transmission
tariff (OATT) to be charged by PJM. Management believes that the FERC
will grant permission for prudently incurred deferred RTO
formation/integration costs to be amortized and included in the OATT.
Whether the amortized costs will be fully recoverable depends upon the
state regulatory commissions' treatment of AEP East companies' portion
of the OATT as these companies file rate cases. Presently, retail base
rates are frozen or capped and cannot be increased for retail customers
of CSPCo, I&M and OPCo.
In August 2004, we intend to file an application with FERC dividing the
RTO information/integration costs between payments made to PJM and all
other costs. We will subsequently request that the payments made
directly to PJM be recovered from all users of PJM's transmission and
that the balance of the deferred costs be recovered from load serving
entities within the area served by the AEP East companies' owned
transmission (AEP zone). Most of the amount recoverable in the AEP zone
will be paid by the AEP East companies since it will be attributable to
their internal load. The amount to be recovered in the AEP zone is
approximately one-half of the deferred costs. In our August application,
we will seek permission to delay the amortization of the AEP zone
deferred amounts until they are recoverable from users of the
transmission system including our retail customers or, as an
alternative, to use a long amortization period that extends beyond the
rate freezes or caps.
The AEP East companies are scheduled to join PJM in October 2004,
although there are pending proceedings in Virginia concerning the
integration into PJM. Therefore, management is unable to predict the
timing of when AEP will join PJM and if upon joining PJM whether FERC
will grant a delay of recovery until the rate caps and freezes end or a
long enough amortization period to allow for the opportunity for
recovery in the East retail jurisdictions. If the AEP East companies do
not obtain regulatory approval to join PJM, we are committed to
reimburse PJM for certain project implementation costs (presently
estimated at $24 million for AEP's share of the entire PJM integration
project). If incurred, PJM project implementation costs will be
allocated among the AEP East companies. Management intends to seek
recovery of the project implementation cost reimbursements, if incurred.
If the FERC ultimately decides not to approve a delay or a long
amortization period or the FERC or the state commissions deny recovery,
future results of operations and cash flows could be adversely affected.
In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO prior to July 1, 2004 and thereafter
only with the approval of the Virginia SCC, but required such transfers
by January 1, 2005. In January 2004, APCo filed with the Virginia SCC a
cost/benefit study covering the time period through 2014 as required by
the Virginia SCC. The study results show a net benefit of approximately
$98 million for APCo over the 11-year study period from AEP's
participation in PJM. In July 2004, after reaching a unanimous agreement
with intervenors to settle the RTO issues in Virginia, the settlement
agreement was submitted to the Virginia SCC. The settlement provides for
approval of APCo's application to join PJM in exchange for a small
annual revenue credit to customers through 2010, or the effective date
of rates established in a new base rate case, some service curtailment
provisions and annual reporting requirements.
In July 2003, the KPSC denied KPCo's request to join PJM based in part
on a lack of evidence that it would benefit Kentucky retail customers.
In August 2003, KPCo sought and was granted a rehearing to submit
additional evidence. In December 2003, AEP filed with the KPSC a
cost/benefit study showing a net benefit of approximately $13 million
for KPCo over the five-year study period from AEP's participation in
PJM. In April 2004, we reached an agreement with interveners to settle
the RTO issues in Kentucky. The KPSC approved the agreement in May 2004
and the FERC approved the settlement in June 2004.
In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to
certain conditions included in the order. The IURC's order stated that
AEP shall request and the IURC shall complete a review of Alliance
formation costs before any future recovery. I&M noted in its response
to the IURC that it deferred such costs under the July 2003 FERC order.
In November 2003, the FERC issued an order preliminarily finding that
AEP must fulfill its CSW merger condition to join an RTO by integrating
into PJM (transmission and markets) by October 1, 2004. The order was
based on PURPA 205(a), which allows FERC to exempt electric utilities
from state law or regulation in certain circumstances. The FERC set
several issues for public hearing before an ALJ. Those issues include
whether the laws, rules, or regulations of Virginia and Kentucky are
preventing AEP from joining an RTO and whether the exceptions under
PURPA 205(a) apply. The FERC ALJ affirmed the FERC's preliminary finding
in March 2004. The FERC issued an order related to this matter in June
2004 affirming its preliminary findings. Virginia has requested a stay
of the FERC order, which was denied, and Virginia now has requested a
stay in the courts.
FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo, I&M, KPCo
and OPCo
- -------------------------------------------------------------------------------
In July 2003, the FERC issued an order directing PJM and the Midwest
Independent System Operator (ISO) to make compliance filings for their
respective OATTs to eliminate the transaction-based charges for through
and out (T&O) transmission service on transactions where the energy is
delivered within the proposed Midwest ISO and PJM expanded regions (RTO
Footprint). The elimination of the T&O rates will reduce the
transmission service revenues collected by the RTOs and thereby reduce
the revenues received by transmission owners under the RTOs' revenue
distribution protocols. The order provided that affected transmission
owners could file to offset the elimination of these revenues by
increasing rates or utilizing a transitional rate mechanism to recover
lost revenues that result from the elimination of the T&O rates. The
FERC also found that the T&O rates of some of the former Alliance RTO
companies, including AEP, may be unjust, unreasonable, and unduly
discriminatory or preferential for energy delivered in the RTO
Footprint. FERC initiated an investigation and hearing in regard to
these rates.
In November 2003, the FERC adopted a new regional rate design and
directed each transmission provider to file compliance rates to
eliminate T&O rates prospectively within the region and simultaneously
implement new seams elimination cost allocation (SECA) rates to mitigate
the lost revenues for a two-year transition period beginning April 1,
2004. The FERC was expected to implement a new rate design after the
two-year period. As required by the FERC, AEP filed compliance tariff
changes in January 2004 to eliminate the T&O charges within the RTO
Footprint. Various parties raised issues with the SECA rate orders and
the FERC implemented settlement procedures before an ALJ.
In March 2004, the FERC approved a settlement that delays elimination of
T&O rates until December 1, 2004 and provides principles and procedures
for a new rate design for the RTO Footprint, to be effective on December
1, 2004. The settlement also provides that if the process does not
result in the implementation of a new rate design on December 1, then
the SECA rates will be implemented and will remain in effect until a new
rate is implemented by the FERC. If implemented, the SECA rate would not
be effective beyond March 31, 2006. The AEP East companies received
approximately $157 million of T&O rate revenues from transactions
delivering energy to customers in the RTO Footprint for the twelve
months ended December 31, 2003. At this time, management is unable to
predict whether the new rate design will fully compensate the AEP East
companies for their lost T&O rate revenues and, consequently, their
impact on future results of operations, cash flows and financial
condition.
Indiana Fuel Order - Affecting I&M
- ----------------------------------
On August 27, 2003, the IURC ordered that certain parties must negotiate
the appropriate action on I&M's fuel cost recovery beginning March 1,
2004, following the February 2004 expiration of a fixed fuel adjustment
charge (fixed pursuant to a prior settlement of the Cook Nuclear Plant
outage issues). The fixed fuel adjustment charge capped fuel recoveries.
In an agreement in connection with AEP's planned corporate separation,
I&M agreed, contingent on AEP implementing the corporate separation,
to a fixed fuel adjustment charge beginning March 2004 and continuing
through December 2007. Although AEP has not corporately separated,
certain parties believe the fixed fuel adjustment charge should
continue. Negotiations with the parties to resolve this issue are
ongoing. The IURC ordered the fixed fuel adjustment charge remain in
place, on an interim basis, for March and April 2004.
In April 2004, the IURC issued an order that extended the interim fuel
factor for May through September 2004, subject to true-up to actual fuel
costs following the resolution of issues in the corporate separation
agreement. The IURC also issued an order that reopened the corporate
separation docket to investigate issues related to the corporate
separation agreement. On July 15, 2004, we filed a fuel factor for the
period October 2004 through March 2005. If the IURC reinstates a fixed
fuel adjustment factor, capping the fuel revenues, results of operations
and cash flows would be adversely affected if fuel costs are
under-recovered.
Michigan 2004 Fuel Recovery Plan - Affecting I&M
- ------------------------------------------------
A 1999 Michigan Public Service Commission's (MPSC) order approved a
Settlement Agreement regarding the extended outage of the Cook Plant and
fixed I&M Power Supply Cost Recovery (PSCR) factors for the St. Joseph
and Three Rivers rate areas through December 2003. As required, I&M
filed its 2004 PSCR Plan with the MPSC on September 30, 2003 seeking new
fuel and power supply recovery factors to be effective in 2004. A public
hearing occurred on March 10, 2004 and a MPSC order is expected during
the second half of 2004. One June 4, 2004, an ALJ recommended that SO2
and NOx costs be excluded. I&M filed exception on June 18, 2004. As
allowed by Michigan law, the proposed factors were effective on January
1, 2004, subject to review and possible adjustment based on the results
of the MPSC order.
4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
------------------------------------------
As discussed in the 2003 Annual Report, certain AEP subsidiaries are
affected by customer choice initiatives and industry restructuring. The
Customer Choice and Industry Restructuring note in the 2003 Annual
Report should be read in conjunction with this report in order to gain a
complete understanding of material customer choice and industry
restructuring matters without significant changes since year-end. The
following paragraphs discuss significant current events related to
customer choice and industry restructuring.
OHIO RESTRUCTURING - Affecting CSPCo and OPCo
- ---------------------------------------------
The Ohio Electric Restructuring Act of 1999 (Ohio Act) provides for a
Market Development Period (MDP) during which retail customers can choose
their electric power suppliers or receive Default Service at frozen
generation rates from the incumbent utility. The MDP began on January 1,
2001 and is scheduled to terminate no later than December 31, 2005. The
Public Utilities Commission of Ohio (PUCO) may terminate the MDP for one
or more customer classes before that date if it determines either that
effective competition exists in the incumbent utility's certified
territory or that there is a twenty percent switching rate of the
incumbent utility's load by customer class. Following the MDP, retail
customers will receive cost-based regulated distribution and
transmission service from the incumbent utility whose distribution rates
will be approved by the PUCO and whose transmission rates will be
approved by the FERC. Retail customers will continue to have the right
to choose their electric power suppliers or receive Default Service,
which must be offered by the incumbent utility at market rates.
On December 17, 2003, the PUCO adopted a set of rules concerning the
method by which it will determine market rates for Default Service
following the MDP. The rule provides for a Market Based Standard Service
Offer (MBSSO) which would be a variable rate based on a transparent
forward market, daily market, and/or hourly market prices. The rule also
requires a fixed-rate Competitive Bidding Process (CBP) for residential
and small nonresidential customers and permits a fixed-rate CBP for
large general service customers and other customer classes. Customers
who do not switch to a competitive generation provider can choose
between them MBSSO or the CBP. Customers who make no choice will be
served pursuant to the CBP. CSPCo and OPCo were granted a waiver from
making the required MBSSO/CBP filing, as a result of their rate
stabilization plan filing.
The PUCO invited default service providers to propose an alternative to
all customers moving to market prices on January 1, 2006. On February 9,
2004, CSPCo and OPCo filed their rate stabilization plan with the PUCO
addressing prices following the end of the MDP. If approved by the PUCO,
prices would be established pursuant to the plan for the period from
January 1, 2006 through December 31, 2008. The plan is intended to
provide price stability and certainty for customers, facilitate the
development of a competitive retail market in Ohio, provide recovery of
environmental and other costs during the plan period and improve the
environmental performance of AEP's generation resources that serve Ohio
customers. The plan includes annual, fixed increases in the generation
component of all customers' bills (3% annually for CSPCo and 7% annually
for OPCo), and the opportunity for additional generation-related
increases upon PUCO review and approval. For residential customers,
however, if the temporary 5% generation rate discount provided by the
Ohio Act was eliminated prior to December 31, 2005 as permitted by the
Ohio Act, the fixed increases would be 1.6% for CSPCo and 5.7% for OPCo.
Any additional generation-related increases under the plan would be
subject to caps. The plan would maintain distribution rates through the
end of 2008 for CSPCo and OPCo at the level effective on December 31,
2005. Such rates could be adjusted for specified reasons. Transmission
charges can be adjusted to reflect applicable charges approved by the
FERC related to open access transmission, net congestion, and ancillary
services. The plan also provides for continued recovery of transition
regulatory assets and deferral of regulatory assets in 2004 and 2005 for
RTO costs and carrying charges on governmentally mandated, mainly
environmental, capital expenditures. Hearings were held in June 2004.
Briefings were completed in July and the cases are pending before the
PUCO. Management cannot predict whether the plan will be approved as
submitted or its impact on results of operations and cash flows.
As provided in stipulation agreements approved by the PUCO in 2000,
CSPCo and OPCo are deferring customer choice implementation costs and
related carrying costs that are in excess of $20 million per company.
The agreements provide for the deferral of these costs as a regulatory
asset until the company's next distribution base rate case. Through
June 30, 2004, CSPCo incurred $35 million and deferred $15 million and
OPCo incurred $37 million and deferred $17 million of such costs. Recovery
of these regulatory assets will be subject to PUCO review in each
company's future Ohio filings for new distribution rates. If the
rate stabilization plan is approved, it would defer recovery of these
amounts until after the end of the rate stabilization period. Management
believes that the customer choice implementation costs were prudently
incurred and the deferred amounts should be recoverable in future rates.
If the PUCO determines that any of the deferred costs are unrecoverable,
it would have an adverse impact on future results of operations and cash
flows.
TEXAS RESTRUCTURING - Affecting SWEPCo, TCC and TNC
- ---------------------------------------------------
Texas Legislation enacted in 1999 provides the framework and timetable
to allow retail electricity competition for all Texas customers. On
January 1, 2002, customer choice of electricity supplier began in the
ERCOT area of Texas. Customer choice has been delayed in the SPP area of
Texas until at least January 1, 2007.
The Texas Legislation, among other things:
o provides for the recovery of regulatory assets and other stranded costs
through securitization and non-bypassable wires charges;
o requires each utility to structurally unbundle into a retail electric
provider, a power generation company and a transmission and distribution
(T&D) utility;
o provides for an earnings test for each of the years 1999 through 2001 and;
o provides for a 2004 true-up proceeding.
The Texas Legislation required vertically integrated utilities to
legally separate their generation and retail-related assets from their
transmission and distribution-related assets. Prior to 2002, TCC and TNC
functionally separated their operations to comply with the Texas
Legislation requirements. AEP formed new subsidiaries to act as
affiliated REPs for TCC and TNC effective January 1, 2002 (the start
date of retail competition). In December 2002, AEP sold the affiliated
REPs to an unaffiliated company.
TEXAS 2004 TRUE-UP PROCEEDINGS
- ------------------------------
The 2004 true-up proceedings will determine the amount and recovery of:
o net stranded generation plant costs and generation-related regulatory assets
(stranded plant costs),
o carrying charges on stranded plant costs from January 2002 (the commencement
date of retail competition),
o a true-up of actual market prices determined through legislatively-mandated
capacity auctions to the power costs used in the PUCT's excess cost over
market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up),
o final approved deferred fuel balance,
o unrefunded accumulated excess earnings,
o excess of price-to-beat revenues over market prices subject to certain
conditions and limitations (retail clawback) and
o other restructuring true-up items.
The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up
proceedings scheduling TCC's filing in September 2004 or 60 days after
the completion of the sale of TCC's generation assets, if later. TNC
filed its 2004 true-up proceeding in June 2004.
Summary of TCC True-up Items:
- -----------------------------
Amount Recorded
at June 30, 2004
----------------
(in millions)
Stranded Generation Plant Costs $1,074 (a)
Unsecuritized Transition Regulatory Asset 194 (a)
Unrefunded Excess Earnings (19) (b)
Other (46)
-------
Amount Subject to Future Securitization 1,203
-------
Wholesale Capacity Auction True-up 480 (c)
Retail Clawback (30) (d)
Deferred Over-recovered Fuel (210) (e)
-------
Other Recoverable Amounts 240
-------
Total Recorded 2004 True-up Balance $1,443 (f)
=======
(a) See "Stranded Costs and Generation-Related Regulatory Assets" section
below for additional information on this item.
(b) See "Unrefunded Excess Earnings" section below for additional information
on this item.
(c) See "Wholesale Capacity Auction True-up" section below for additional
information on this item.
(d) See "Retail Clawback" section below for additional information on this
item.
(e) See "Fuel Balance Recoveries" section below for additional information on
this item.
(f) See "Stranded Cost Recovery" section below for summary of this balance.
Stranded Costs and Generation-Related Regulatory Assets
- -------------------------------------------------------
Restructuring legislation required utilities with stranded costs to use
market-based methods to value certain generation assets for determining
stranded costs. TCC is the only AEP subsidiary that has stranded costs
under the Texas Legislation. TCC elected to use the sale of assets
method to determine the market value of TCC's generation assets for
stranded cost purposes. For purposes of the 2004 true-up proceeding, the
amount of stranded costs under this market valuation methodology will be
the amount by which the book value of TCC's generation assets, including
regulatory assets and liabilities that were not securitized, exceeds the
market value of the generation assets as measured by the net proceeds
from the sale of the assets. Based on the prices established by the
sales, discussed below, TCC's stranded costs from the sale of generation
assets and remaining generation-related net regulatory assets are
estimated to be $1.3 billion ($1,074 million and $194 million, described
later in this section) before accrual of any applicable carrying
charges.
In June 2003, TCC began actively seeking buyers for 4,497 megawatts of
TCC's generating capacity in Texas with a net book value of $1.9 billion
at June 30, 2004. We received bids for all of TCC's generation plants.
In January 2004, TCC agreed to sell its 7.81% ownership interest in the
Oklaunion Power Station to an unaffiliated third party for approximately
$43 million. In March 2004, TCC agreed to sell its 25.2% ownership
interest in STP for approximately $333 million and its other coal, gas
and hydro plants for approximately $430 million to unaffiliated
entities. Each sale is subject to specified price adjustments. TCC sent
right of first refusal notices to the co-owners of Oklaunion and STP.
TCC filed for FERC approval of the sales of Oklaunion and the fossil and
hydro plants. TCC received a notice from a co-owner of Oklaunion and STP
exercising their right of first refusal; therefore, SEC approval will be
required. The original unaffiliated third party purchaser of Oklaunion
has petitioned for a court order declaring its contract valid and that
the co-owners' rights of first refusal are void. Approval of the sale of
STP from the Nuclear Regulatory Commission is required. On July 1, 2004,
we completed the sale of the other coal, gas and hydro plants for
approximately $425 million, net of adjustments. The completion of the
sales of STP and Oklaunion plants is expected to occur in 2004, subject
to rights of first refusal and the necessary regulatory approvals. In
order to sell these assets, TCC defeased all of its remaining
outstanding first mortgage bonds in May 2004. TCC will file its 2004
true-up proceeding with the PUCT after the completion of the sale of the
generation assets.
After the 2004 true-up proceeding, TCC may recover stranded costs and
other true-up amounts through distribution rates as a competition
transition charge and may seek to issue securitization revenue bonds for
its stranded plant costs and remaining generation net regulatory assets.
The cost of the securitization bonds is recovered through distribution
rates as a separate transition charge. TCC recognized an impairment of
its generation assets in December 2003 as a regulatory asset. At June
30, 2004, this regulatory asset was approximately $1,074 million. The
recovery of this regulatory asset and the remaining $194 million of
generation-related net regulatory assets will be subject to review and
approval by the PUCT as a stranded plant cost in the 2004 true-up
proceeding.
Carrying Charges On Recoverable Stranded Costs
- ----------------------------------------------
In December 2001, the PUCT issued a rule concerning stranded cost
true-up proceedings stating, among other things, that carrying costs on
stranded costs would begin to accrue on the date that the PUCT issued
its final order in the 2004 true-up proceeding. TCC and one other Texas
electric utility company filed a direct appeal of the rule to the Texas
Third Court of Appeals contending that carrying costs should commence on
January 1, 2002, the day that retail customer choice began in ERCOT.
The Third Court of Appeals ruled against the companies, who then
appealed to the Texas Supreme Court. On June 18, 2004, the Texas Supreme
Court reversed the decision of the Third Court of Appeals determining
that a carrying cost should be accrued beginning January 1, 2002 and
remanded the proceeding to the PUCT for further consideration. The
Supreme Court determined that utilities with stranded costs are not
permitted to over-recover stranded costs and the PUCT should address
whether the 2002 and 2003 wholesale capacity auction true-up regulatory
asset includes a recovery of stranded costs. Industrial intervenors have
filed a motion for rehearing with the Supreme Court which has not been
decided.
The PUCT has indicated that it will consider the Supreme Court's
decision in hearings to be held for another utility in September 2004.
The decision in that proceeding could have an impact on TCC. Since the
impact of these future PUCT proceedings cannot be determined at this
time, TCC has not recorded the carrying charge as a regulatory asset
through June 30, 2004.
Wholesale Capacity Auction True-up
- ----------------------------------
Texas Legislation required that electric utilities and their affiliated
power generation companies (PGC) offer for sale at auction, in 2002 and
2003 and after, at least 15% of the PGC's Texas jurisdictional installed
generation capacity in order to promote competitiveness in the wholesale
market through increased availability of generation. Actual market power
prices received in the state-mandated auctions will be used to calculate
the wholesale capacity auction true-up adjustment for TCC for the 2004
true-up proceeding. According to PUCT rules, the wholesale capacity
auction true-up is only applicable to the years 2002 and 2003. TCC
recorded a $480 million regulatory asset and related revenues which
represent the quantifiable amount of the wholesale capacity auction
true-up for the years 2002 and 2003.
In the fourth quarter of 2003, the PUCT approved a true-up filing
package containing calculation instructions similar to the methodology
employed by TCC to calculate the amount recorded for recovery under its
wholesale capacity auction true-up. The PUCT will review the $480
million wholesale capacity auction true-up regulatory asset for recovery
as part of the 2004 true-up proceeding.
Fuel Balance Recoveries
- -----------------------
In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail
sales within its ERCOT service area for inclusion in the 2004 true-up
proceeding. In January 2004, the PUCT announced a final ruling in TNC's
fuel reconciliation case. The PUCT issued a written order in March 2004
that established TNC's unrecovered fuel balance for the ERCOT service
territory. Various parties, including TNC, requested rehearing of the
PUCT's order. In May 2004, the PUCT reversed certain prior rulings
resulting in TNC having a final fuel over-recovery balance of
approximately $7 million. TNC's 2004 true-up proceeding, filed in June
2004, will be updated to reflect the balance after the PUCT issues a
final fuel order. TNC has provided for all to-date disallowances pending
receipt of the final order. Management is unable to predict the amount
of TNC's fuel over-recovery which will be included in its 2004 true-up
proceedings.
In 2002, TCC filed with the PUCT to reconcile fuel costs and to
establish its deferred over-recovery of fuel balance for inclusion in
the 2004 true-up proceeding. In May 2004, the PUCT remanded TCC's fuel
proceeding to the ALJ. TCC has provided $210 million for its
over-recovery balance at June 30, 2004. TCC has provided for all to-date
disallowances pending receipt of a final order. Management is unable to
predict the amount of TCC's fuel over-recovery which will be included in
its 2004 true-up proceeding.
See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 3 "Rate
Matters" for further discussion.
Unrefunded Excess Earnings
- --------------------------
The Texas Legislation provides for the calculation of excess earnings
for each year from 1999 through 2001. The total excess earnings
determined for the three-year period were $3 million for SWEPCo, $47
million for TCC and $19 million for TNC. TCC, TNC and SWEPCo challenged
the PUCT's treatment of fuel-related deferred income taxes and appealed
the PUCT's final 2000 excess earnings to the Travis County District
Court which upheld the PUCT ruling. The District Court's ruling was
appealed to the Third Court of Appeals. In August 2003, the Third Court
of Appeals reversed the PUCT order and the District Court judgment. The
PUCT's request for rehearing of the Appeals Court's decision was denied
and the PUCT chose not to appeal the ruling any further. The District
Court remanded to the PUCT an appeal of the same issue from the PUCT's
2001 order to be consistent with the Court of Appeals decision. Since an
expense and regulatory liability had been accrued in prior years in
compliance with the PUCT orders, the companies reversed a portion of
their regulatory liability for the years 2000 and 2001 consistent with
the Appeals Court's decision and credited amortization expense during
the third quarter of 2003.
In 2001, the PUCT issued an order requiring TCC to return estimated
excess earnings by reducing distribution rates by approximately $55
million plus accrued interest over a five-year period beginning January
1, 2002. Since excess earnings amounts were expensed in 1999, 2000 and
2001, the order has no additional effect on reported net income but will
reduce cash flows for the five-year refund period. The amount to be
refunded is recorded as a regulatory liability ($19 million at June 30,
2004). Management believes that TCC will have stranded costs and that it
was inappropriate for the PUCT to order a refund prior to TCC's 2004
true-up proceeding. TCC appealed the PUCT's refund of excess earnings to
the Travis County District Court. That court affirmed the PUCT's
decision and further ordered that the refunds be provided to ultimate
customers. TCC has appealed the decision to the Court of Appeals.
Retail Clawback
- ---------------
The Texas Legislation provides for the affiliated price-to-beat (PTB)
retail electric providers (REP) serving residential and small commercial
customers to refund to its T&D utility the excess of the PTB revenues
over market prices (subject to certain conditions and a limitation of
$150 per customer). This is the retail clawback. If, prior to January 1,
2004, 40% of the load for the residential or small commercial classes is
served by competitive REPs, the retail clawback is not applicable for
that class of customer. During 2003, TCC and TNC filed to notify the
PUCT that competitive REPs serve over 40% of the load in the small
commercial class. The PUCT approved TCC's and TNC's filings in December
2003. In 2002, AEP had accrued a regulatory liability of approximately
$9 million for the small commercial retail clawback on its REP's books.
When the PUCT certified that the REP's in TCC and TNC service
territories had reached the 40% threshold, the regulatory liability was
no longer required for the small commercial class and was reversed in
December 2003. Based upon customer information filed by the unaffiliated
company which operates as the affiliated REP for TCC and TNC, we updated
the estimated retail clawback regulatory liability in May 2004. At June
30, 2004, the retail clawback regulatory liability was $30 million for
TCC and $7 million for TNC.
TNC 2004 True-up Filing
- -----------------------
In June 2004, TNC filed its 2004 true-up proceeding including the fuel
reconciliation balance and the retail clawback calculation. The amount
of deferred fuel, an over-recovery balance of $7 million at June 30, 2004,
remains under review by the PUCT and is subject to possible revision.
The retail clawback regulatory liability was adjusted in the second
quarter of 2004 to $7 million (TNC's allocated portion of the REP's
retail clawback) reflecting the number of customers served on January 1,
2004. The PUCT has deferred this proceeding pending the resolution of
the final fuel proceeding.
Stranded Cost Recovery
- ----------------------
When the 2004 true-up proceeding is completed, TCC intends to file to
recover PUCT-approved stranded costs and other true-up amounts that are
in excess of current securitized amounts, plus appropriate carrying
charges, through non-bypassable competition transition charge in the
regulated T&D rates. TCC may also seek to securitize the approved stranded
plant costs and generation-related net regulatory assets that were not
previously recovered through a prior securitization and the
non-bypassable transition charge. The annual costs of securitization are
recovered through the non-bypassable transition charge collected by the
T&D utility over the term of the securitization bonds.
TCC's recorded net regulatory asset for amounts subject to approval in the 2004
true-up proceeding is approximately $1.4 billion. Management estimates
that TCC's 2004 true-up filing will exceed the total of its recorded net
regulatory asset. Management expects that the 2004 true-up proceeding
will be contentious and could possibly result in disallowances.
In the event we are unable, after the 2004 true-up proceeding, to
recover all or a portion of our stranded plant costs, generation-related
net regulatory assets, wholesale capacity auction true-up regulatory
assets, other restructuring true-up items and costs, it could have a
material adverse effect on results of operations, cash flows and
possibly financial condition.
VIRGINIA RESTRUCTURING - Affecting APCo
- ---------------------------------------
In April 2004, the Governor of Virginia signed legislation which extends
the transition period for electricity restructuring, including capped
rates, through December 31, 2010. The legislation provides specific cost
recovery opportunities during the capped rate period, including two
optional general based rate changes and an opportunity for recovery,
through a separate rate mechanism, of incremental environmental and
reliability costs.
5. COMMITMENTS AND CONTINGENCIES
-----------------------------
As discussed in the Commitments and Contingencies note within the 2003
Annual Report, certain AEP subsidiaries continue to be involved in
various legal matters. The 2003 Annual Report should be read in
conjunction with this report in order to understand the other material
nuclear and operational matters without significant changes since their
disclosure in the 2003 Annual Report. The material matters discussed in
the 2003 Annual Report without significant changes in status since
year-end include, but are not limited to, (1) nuclear matters, (2)
construction commitments, (3) potential uninsured losses, (4) merger
litigation, and (5) FERC proposed Standard Market Design. See disclosure
below for significant matters with changes in status subsequent to the
disclosure made in the 2003 Annual Report.
ENVIRONMENTAL
- -------------
Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M,
and OPCo
- ---------------------------------------------------------------------------
The Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo
and other unaffiliated utilities modified certain units at coal-fired
generating plants in violation of the new source review requirements of
the Clean Air Act (CAA). The Federal EPA filed its complaints against
AEP subsidiaries in U.S. District Court for the Southern District of
Ohio. The court also consolidated a separate lawsuit, initiated by
certain special interest groups, with the Federal EPA case. The alleged
modifications relate to costs that were incurred at the generating units
over a 20-year period.
Under the CAA, if a plant undertakes a major modification that directly
results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution
control technology. This requirement does not apply to activities such
as routine maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and efficient
operation of the plant. The CAA authorizes civil penalties of up to
$27,500 per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). In 2001, the District Court ruled claims for
civil penalties based on activities that occurred more than five years
before the filing date of the complaints cannot be imposed. There is no
time limit on claims for injunctive relief.
On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in
order to "perfect" its complaint in the pending litigation. The NOV
expands the number of alleged "modifications" undertaken at the
Muskingum River, Cardinal, Conesville and Tanners Creek plants during
scheduled outages on these units from 1979 through the present.
Approximately one-third of the allegations in the NOV are already
contained in allegations made by the states or the special interest
groups in the pending litigation. The Federal EPA is expected to file a
motion to amend its complaint, and, to the extent that motion seeks to
expand the scope of the pending litigation, the AEP subsidiaries will
oppose that motion.
On August 7, 2003, the District Court issued a decision following a
liability trial in a case pending in the Southern District of Ohio
against Ohio Edison Company, an unaffiliated utility. The District Court
held that replacements of major boiler and turbine components that are
infrequently performed at a single unit, that are performed with the
assistance of outside contractors, that are accounted for as capital
expenditures, and that require the unit to be taken out of service for a
number of months are not "routine" maintenance, repair, and replacement.
The District Court also held that a comparison of past actual emissions
to projected future emissions must be performed prior to any non-routine
physical change in order to evaluate whether an emissions increase will
occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all
of the challenged activities in that case were not routine, and that the
changes resulted in significant net increases in emissions for certain
pollutants. A remedy trial was scheduled for July 2004, but has been
postponed until January 2005 to facilitate further settlement
negotiations.
Management believes that the Ohio Edison decision fails to properly
evaluate and apply the applicable legal standards. The facts in the AEP
case also vary widely from plant to plant. Further, the Ohio Edison
decision is limited to liability issues, and provides no insight as to
the remedies that might ultimately be ordered by the Court.
On August 26, 2003, the District Court for the Middle District of South
Carolina issued a decision on cross-motions for summary judgment prior
to a liability trial in a case pending against Duke Energy Corporation,
an unaffiliated utility. The District Court denied all the pending
motions, but set forth the legal standards that will be applied at the
trial in that case. The District Court determined that the Federal EPA
bears the burden of proof on the issue of whether a practice is "routine
maintenance, repair, or replacement" and on whether or not a
"significant net emissions increase" results from a physical change or
change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the
relevant source category" in determining if it is "routine." Further,
the Federal EPA must calculate emissions by determining first whether a
change in the maximum achievable hourly emission rate occurred as a
result of the change, and then must calculate any change in annual
emissions holding hours of operation constant before and after the
change. The Federal EPA requested reconsideration of this decision, or
in the alternative, certification of an interlocutory appeal to the
Fourth Circuit Court of Appeals, and the District Court denied the
Federal EPA's motion. On April 13, 2004, the parties filed a joint
motion for entry of final judgment, based on stipulations of relevant
facts that obviated the need for a trial, but preserving plaintiffs'
right to seek an appeal of the federal prevention of significant
deterioration (PSD) claims. On April 14, 2004, the Court entered final
judgment for Duke Energy on all of the PSD claims made in the amended
complaints, and dismissed all remaining claims with prejudice. The
United States subsequently filed a notice of appeal to the Fourth
Circuit Court of Appeals, which issued a briefing order requiring the
case to be fully briefed by late September 2004.
On June 24, 2003, the United States Court of Appeals for the 11th
Circuit issued an order invalidating the administrative compliance order
issued by the Federal EPA to the Tennessee Valley Authority for alleged
CAA violations. The 11th Circuit determined that the administrative
compliance order was not a final agency action, and that the enforcement
provisions authorizing the issuance and enforcement of such orders under
the CAA are unconstitutional. The United States filed a petition for
certiorari with the United States Supreme Court and on May 3, 2004, that
petition was denied.
On June 26, 2003, the United States Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group
(UARG), of which the AEP subsidiaries are members, to reopen petitions
for review of the 1980 and 1992 Clean Air Act rulemakings that are the
basis for the Federal EPA claims in the AEP case and other related
cases. On August 4, 2003, UARG filed a motion to separate and expedite
review of their challenges to the 1980 and 1992 rulemakings from other
unrelated claims in the consolidated appeal. The Circuit Court denied
that motion on September 30, 2003. The central issue in these petitions
concerns the lawfulness of the emissions increase test, as currently
interpreted and applied by the Federal EPA in its utility enforcement
actions. A decision by the D. C. Circuit Court could significantly
impact further proceedings in the AEP case.
On August 27, 2003, the Administrator of the Federal EPA signed a final
rule that defines "routine maintenance repair and replacement" to
include "functionally equivalent equipment replacement." Under the new
final rule, replacement of a component within an integrated industrial
operation (defined as a "process unit") with a new component that is
identical or functionally equivalent will be deemed to be a "routine
replacement" if the replacement does not change any of the fundamental
design parameters of the process unit, does not result in emissions in
excess of any authorized limit, and does not cost more than twenty
percent of the replacement cost of the process unit. The new rule is
intended to have a prospective effect, and was to become effective in
certain states 60 days after October 27, 2003, the date of its
publication in the Federal Register, and in other states upon completion
of state processes to incorporate the new rule into state law. On
October 27, 2003 twelve states, the District of Columbia and several
cities filed an action in the United States Court of Appeals for the
District of Columbia Circuit seeking judicial review of the new rule.
The UARG has intervened in this case. On December 24, 2003, the Circuit
Court granted a motion from the petitioners to stay the effective date
of this rule, which had been December 26, 2003.
Management is unable to estimate the loss or range of loss related to
any contingent liability the AEP subsidiaries might have for civil
penalties under the CAA proceedings. Management is also unable to
predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be
determined by the Court. If the AEP System companies do not prevail, any
capital and operating costs of additional pollution control equipment
that may be required, as well as any penalties imposed, would adversely
affect future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated rates and
market prices for electricity.
In December 2000, Cinergy Corp., an unaffiliated utility, which operates
certain plants jointly owned by CSPCo, reached a tentative agreement
with the Federal EPA and other parties to settle litigation regarding
generating plant emissions under the Clean Air Act. Negotiations are
continuing between the parties in an attempt to reach final settlement
terms. Cinergy's settlement could impact the operation of Zimmer Plant
and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%,
respectively, by CSPCo). Until a final settlement is reached, CSPCo will
be unable to determine the settlement's impact on its jointly owned
facilities and its future results of operations and cash flows.
On July 21, 2004, the Sierra Club issued a notice of intent to file a
citizen suit claim against DPL, Inc., Cinergy Corporation, CSPCo, and
The Dayton Power & Light Company for alleged violations of the New
Source Review programs at the Stuart Station. CSPCo owns a 26% share of
the Stuart Station. Management is unable to predict the timing of any
future action by the special interest group or the effect of such
actions on future operations or cash flows.
SWEPCo Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo
- --------------------------------------------------------------------------
On July 13, 2004, two special interest groups issued a notice of intent
to commence a citizen suit under the Clean Air Act for alleged
violations of various permit conditions in permits issued to SWEPCo's
Welsh, Knox Lee, and Pirkey plants. This notice was prompted by allegations
made by a terminated AEP employee. The allegations at the Welsh Plant
concern compliance with emission limitations on particulate matter and
carbon monoxide, compliance with a referenced design heat input 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.
SWEPCo is preparing additional responses to the Notice of Enforcement
and the notice from the special interest groups. Management is unable to
predict the timing of any future action by TCEQ or the special interest
groups or the effect of such actions on results of operations, financial
condition or cash flows.
Carbon Dioxide Public Nuisance Claims - Affecting AEP System
- -------------------------------------------------------------
On July 21, 2004, attorneys general from eight states and the
corporation counsel for the City of New York filed an action in federal
district court for the Southern District of New York against AEP, AEPSC
and four other unaffiliated governmental and investor-owned electric
utility systems. That same day, a similar complaint was filed in the
same court against the same defendants by the Natural Resources Defense
Council on behalf of two special interest groups. The actions allege
that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts
associated with global warming, and seek injunctive relief in the form
of specific emission reduction commitments from the defendants.
Management believes the actions are without merit and intends to
vigorously defend against the claims.
Nuclear Decommissioning - Affecting TCC
- ---------------------------------------
As discussed in the 2003 Annual Report, decommissioning costs are
accrued over the service life of STP. The licenses to operate the two
nuclear units at STP expire in 2027 and 2028. TCC had estimated its
portion of the costs of decommissioning STP to be $289 million in 1999
nondiscounted dollars. TCC is accruing and recovering these
decommissioning costs through rates based on the service life of STP at
a rate of approximately $8 million per year.
In May 2004, an updated decommissioning study was completed for STP. The
study estimates TCC's share of the decommissioning costs of STP to be
$344 million in nondiscounted 2004 dollars. As discussed in Note 7, TCC
is in the process of selling its ownership interest in STP to a
non-affiliate, and upon completion of the sale it is anticipated that
TCC will no longer be obligated for nuclear decommissioning liabilities
associated with STP.
OPERATIONAL
- -----------
Power Generation Facility - Affecting OPCo
- ------------------------------------------
AEP has agreements with Juniper Capital L.P. (Juniper) under which
Juniper constructed and financed a non-regulated merchant power
generation facility (Facility) near Plaquemine, Louisiana and leased the
Facility to AEP. AEP has subleased the Facility to the Dow Chemical
Company (Dow). The Facility is a Dow-operated "qualifying cogeneration
facility" for purposes of PURPA. Commercial operation of the Facility as
required by the agreements between Juniper, AEP and Dow was achieved on
March 18, 2004.
Dow uses a portion of the energy produced by the Facility and sells the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of
such excess energy from Dow. Because the Facility is a major steam
supply for Dow, Dow is expected to operate the Facility at certain
minimum levels, and OPCo is obligated to purchase the energy generated
at those minimum operating levels (expected to be approximately 270 MW).
OPCo has also agreed to sell up to approximately 800 MW of energy to
Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a
Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a
price that is currently in excess of market. OPCo has entered an
agreement with an affiliate that eliminates OPCo's market exposure
related to the PPA. AEP has guaranteed this affiliate's performance
under the agreement. Beginning May 1, 2003, OPCo tendered replacement
capacity, energy and ancillary services to TEM pursuant to the PPA which
TEM rejected as non-conforming. Commercial operation for purposes of the
PPA began April 2, 2004.
On September 5, 2003, TEM and OPCo separately filed declaratory judgment
actions in the United States District Court for the Southern District of
New York. OPCo alleges that TEM has breached the PPA, and is seeking a
determination of OPCo's rights under the PPA. TEM alleges that the PPA
never became enforceable or alternatively, that the PPA has already been
terminated as the result of OPCo's breaches. If the PPA is deemed
terminated or found to be unenforceable by the court, OPCo could be
adversely affected to the extent it is unable to find other purchasers
of the power with similar contractual terms and to the extent OPCo does
not fully recover claimed termination value damages from TEM. 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.
Enron Bankruptcy - Affecting APCo, CSPCo, I&M, KPCo and OPCo
- -----------------------------------------------------------
In 2002, certain subsidiaries of AEP filed claims against Enron and its
subsidiaries in the Enron bankruptcy proceeding pending in the U.S.
Bankruptcy Court for the Southern District of New York. At the date of
Enron's bankruptcy, certain subsidiaries of AEP had open trading
contracts and trading accounts receivables and payables with Enron. In
addition, on June 1, 2001, AEP purchased Houston Pipe Line Company (HPL)
from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.
Commodity trading settlement disputes - In September 2003, Enron filed a
complaint in the Bankruptcy Court against AEPES challenging AEP's
offsetting of receivables and payables and related collateral across
various Enron entities and seeking payment of approximately $125 million
plus interest in connection with gas-related trading transactions. The
AEP subsidiaries asserted their right to offset trading payables owed to
various Enron entities against trading receivables due to several AEP
subsidiaries. The parties are currently in non-binding court-sponsored
mediation.
In December 2003, Enron filed a complaint in the Bankruptcy Court
against AEPSC seeking approximately $93 million plus interest in
connection with a transaction for the sale and purchase of physical
power among Enron, AEP and Allegheny Energy Supply, LLC during November
2001. Enron's claim seeks to unwind the effects of the transaction. AEP
believes it has several defenses to the claims in the action being
brought by Enron. The parties are currently in non-binding
court-sponsored mediation.
Enron bankruptcy summary - The amount expensed in prior years in
connection with the Enron bankruptcy was based on an analysis of
contracts where AEP and Enron entities are counterparties, the
offsetting of receivables and payables, the application of deposits from
Enron entities and management's analysis of the HPL related purchase
contingencies and indemnifications. As noted above, Enron has challenged
the offsetting of receivables and payables. Management is unable to
predict the outcome of these lawsuits or their impact on results of
operations, cash flows and financial condition.
Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC
- ------------------------------------------------------------
Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider
(REP), filed a lawsuit in federal District Court in Corpus Christi,
Texas, in July 2003, against AEP and four of its subsidiaries, including
TCC and TNC, certain unaffiliated energy companies and ERCOT. The action
alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made
against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price
spikes requiring TCE to post additional collateral and ultimately forced
it into bankruptcy when it was unable to raise prices to its customers
due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary
damages and court costs. Two additional parties, Utility Choice, LLC and
Cirro Energy Corporation, have sought leave to intervene as plaintiffs
asserting similar claims. AEP and its subsidiaries filed a Motion to
Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. AEP and its subsidiaries filed a Motion to Dismiss the
amended complaint. In June 2004, the Court dismissed all claims against
the AEP companies. TCE has appealed the trial court's decision to the
United States Court of Appeals for the Fifth Circuit.
Energy Market Investigation - Affecting AEP System
- --------------------------------------------------
AEP and other energy market participants received data requests,
subpoenas and requests for information from the FERC, the SEC, the PUCT,
the U.S. Commodity Futures Trading Commission (CFTC), the U.S.
Department of Justice and the California attorney general during 2002.
Management responded to the inquiries and provided the requested
information and has continued to respond to supplemental data requests
in 2003 and 2004.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES
in federal district court in Columbus, Ohio. The CFTC alleges that AEP
and AEPES provided false or misleading information about market
conditions and prices of natural gas in an attempt to manipulate the
price of natural gas in violation of the Commodity Exchange Act. The
CFTC seeks civil penalties, restitution and disgorgement of benefits. 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 what, if any, further action, these
governmental agencies may take with respect to these matters.
FERC Market Power Mitigation - Affecting AEP System
- ---------------------------------------------------
A FERC order issued in November 2001 on AEP's triennial market based
wholesale power rate authorization update required certain mitigation
actions that AEP would need to take for sales/purchases within its
control area and required AEP to post information on its website
regarding its power system's status. As a result of a request for
rehearing filed by AEP and other market participants, FERC issued an
order delaying the effective date of the mitigation plan until after a
planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a
technical conference in January 2004. In April 2004, the FERC issued two
orders concerning utilities' ability to sell wholesale electricity at
market-based rates. In the first order, the FERC adopted two new interim
screens for assessing potential generation market power of applicants
for wholesale market based rates, and described additional analyses and
mitigation measures that could be presented if an applicant does not
pass one of these interim screens. In July 2004, the FERC issued an
order on rehearing affirming its conclusions in the April order and
directing AEP and two unaffiliated utilities to file generation market
power analyses within 30 days. In the second order, the FERC initiated a
rulemaking to consider whether the FERC's current methodology for
determining whether a public utility should be allowed to sell wholesale
electricity at market-based rates should be modified in any way.
We plan to present evidence to demonstrate that we do not possess market
power in geographic areas where we sell wholesale power.
6. GUARANTEES
----------
There are no material liabilities recorded for guarantees in accordance
with FIN 45. There is no collateral held in relation to any guarantees
and there is no recourse to third parties in the event any guarantees
are drawn unless specified below.
Letter of Credit
- ----------------
TCC has entered into a standby letter of credit (LOC) with third
parties. This LOC covers credit enhancements for issued bonds. This LOC
was issued in TCC's ordinary course of business. At June 30, 2004, the
maximum future payments of the LOC are $43 million which matures
November 2005. There is no recourse to third parties in the event this
letter of credit is drawn.
SWEPCo
- ------
In connection with reducing the cost of the lignite mining contract for
its Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain
conditions, to assume the capital lease obligations and term loan
payments of the mining contractor, Sabine Mining Company (Sabine). In
the event Sabine defaults under any of these agreements, SWEPCo's total
future maximum payment exposure is approximately $51 million with
maturity dates ranging from June 2005 to February 2012.
As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining, SWEPCo has agreed to provide
guarantees of mine reclamation in the amount of approximately $85
million. Since SWEPCo uses self-bonding, the guarantee provides for
SWEPCo to commit to use its resources to complete the reclamation in the
event the work is not completed by a third party miner. At June 30,
2004, the cost to reclaim the mine in 2035 is estimated to be
approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.
On July 1, 2003, SWEPCo consolidated Sabine due to the application of
FIN 46 (see Note 2). Upon consolidation, SWEPCo recorded the assets and
liabilities of Sabine ($78 million). Also, after consolidation, SWEPCo
currently records all expenses (depreciation, interest and other
operation expense) of Sabine and eliminates Sabine's revenues against
SWEPCo's fuel expenses. There is no cumulative effect of an accounting
change recorded as a result of the requirement to consolidate, and there
is no change in net income due to the consolidation of Sabine. SWEPCo
dos not have an ownership interest in Sabine.
Indemnifications and Other Guarantees
- -------------------------------------
All of the registrant subsidiaries enter into certain types of
contracts, which would require indemnifications. Typically these
contracts include, but are not limited to, sale agreements, lease
agreements, purchase agreements and financing agreements. Generally
these agreements may include, but are not limited to, indemnifications
around certain tax, contractual and environmental matters. With respect
to sale agreements, exposure generally does not exceed the sale price.
Registrant subsidiaries cannot estimate the maximum potential exposure
for any of these indemnifications entered into prior to December 31,
2002 due to the uncertainty of future events. In 2003 and during the
first six months of 2004, registrant subsidiaries entered into sale
agreements which included indemnifications with a maximum exposure that
was not significant for any individual registrant subsidiary except for
TCC which entered into an indemnification of $129 million relating to
the sale of its generation assets on July 1, 2004 (see note 7). There
are no material liabilities recorded for any indemnifications.
Certain registrant subsidiaries lease certain equipment under a master
operating lease. Under the lease agreement, the lessor is guaranteed to
receive up to 87% of the unamortized balance of the equipment at the end
of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, we have
committed to pay the difference between the fair market value and the
unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At June 30, 2004, the maximum potential loss by
subsidiary for these lease agreements assuming the fair market value of
the equipment is zero at the end of the lease term is as follows:
Maximum Potential Loss
Subsidiary (in millions)
---------- -------------
APCo $5
CSPCo 2
I&M 3
KPCo 1
OPCo 4
PSO 4
SWEPCo 4
TCC 6
TNC 3
7. DISPOSITIONS AND ASSETS HELD FOR SALE
-------------------------------------
Texas Plants
- ------------
In December 2002, TCC filed a plan of divestiture with the PUCT
proposing to sell all of its power generation assets, including the
eight gas-fired generating plants that were either deactivated or
designated as "reliability must run" status.
During the fourth quarter of 2003, after receiving bids from interested
buyers, TCC recorded a $938 million impairment loss and changed the
classification of the plant assets from plant in service to Assets Held
for Sale. In accordance with Texas legislation, the $938 million
impairment was offset by the establishment of a regulatory asset, which
is expected to be recovered through a wires charge, subject to the final
outcome of the 2004 Texas true-up proceeding. As a result of the 2004
true-up proceeding, if we are unable to recover all or a portion of our
requested costs (see Note 4), any unrecovered costs could have a
material adverse effect on our results of operations, cash flows and
possibly financial condition.
During early 2004, TCC signed agreements to sell all of its generating
assets, at prices which approximate book value after considering the
impairment charge described above. As a result, TCC does not expect
these pending asset sales, described below, to have a significant effect
on its future results of operations, except in the case that our true-up
proceedings, as described above, do not allow for recovery of our
stranded costs.
Oklaunion Power Station
-----------------------
In April 2004, TCC signed an agreement to sell its 7.81 percent
share of Oklaunion Power Station for approximately $43 million
(subject to closing adjustments) to an unrelated party. In May
2004, TCC received notice from co-owners of the Oklaunion Power
Station, announcing their decision to exercise their right of
first refusal, with terms similar to the original agreement. The
sale is currently being challenged by the unrelated party with
which TCC entered into the original sales agreement. The
unrelated party alleges that the co-owner has exceeded its legal
authority and has requested that the court declare the one
co-owner's exercise of its right of first refusal void. The
unrelated party further argues that the second of the two
co-owner's exercise of its right of first refusal is not timely
and invalid. TCC expects that it will be able to resolve this
legal issue and that the planned sale will close by the end of
2004.
South Texas Project
-------------------
In February 2004, TCC signed an agreement to sell its 25.2
percent share of the South Texas Project (STP) nuclear plant for
approximately $333 million, subject to closing adjustments. In
June 2004, TCC received notice from co-owners of their decisions
to exercise their rights of first refusal, with terms similar to
the original agreement. TCC expects the sale to close before the
end of 2004 subject to necessary regulatory approval.
TCC Generation Assets
---------------------
In March 2004, TCC signed an agreement to sell its remaining
generating assets, including eight natural gas plants, one
coal-fired plant and one hydro plant to a non-related joint
venture. The sale was completed in July 2004 for approximately
$425 million, net of adjustments. The sale did not have a
significant effect on TCC's results of operation during the
second quarter 2004.
The assets and liabilities of the TCC plants held for sale at June 30,
2004 and December 31, 2003 are as follows:
June 30, 2004 December 31, 2003
------------- -----------------
Assets: (in millions)
------
Other Current Assets $58 $57
Property, Plant and Equipment, Net 796 797
Regulatory Assets 51 49
Decommissioning Trusts 132 125
------- -------
Total Assets Held for Sale $1,037 $1,028
======= =======
Liabilities:
-----------
Regulatory Liabilities $9 $9
Asset Retirement Obligations 227 219
------- -------
Total Liabilities Held for Sale $236 $228
======= =======
8. BENEFIT PLANS
-------------
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in
AEP sponsored U.S. qualified pension plans and nonqualified pension
plans. A substantial majority of employees are covered by either one
qualified plan or both a qualified and a nonqualified pension plan. In
addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWPECo, TCC and TNC
participate in other postretirement benefit plans sponsored by AEP to
provide medical and death benefits for retired employees in the U.S.
The following tables provide the components of AEP's net periodic
benefit cost (credit) for the plans for the three and six months ended
June 30, 2004 and 2003:
Three Months ended June 30, 2004 and 2003:
- -----------------------------------------
U.S.
U.S. Other Postretirement
Pension Plans Benefit Plans
--------------------- ------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Service Cost $21 $20 $10 $11
Interest Cost 57 59 30 33
Expected Return on Plan Assets (73) (80) (20) (17)
Amortization of Transition
(Asset) Obligation 1 (2) 7 6
Amortization of Net Actuarial Loss 4 3 9 13
---- ---- ---- ----
Net Periodic Benefit Cost (Credit) $10 $- $36 $46
==== ==== ==== ====
Six Months ended June 30, 2004 and 2003:
- ---------------------------------------
U.S.
U.S. Other Postretirement
Pension Plans Benefit Plans
--------------------- ------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Service Cost $43 $40 $20 $21
Interest Cost 114 117 59 65
Expected Return on Plan Assets (146) (159) (41) (32)
Amortization of Transition
(Asset) Obligation 1 (4) 14 14
Amortization of Net Actuarial Loss 8 5 18 26
---- ----- ---- ----
Net Periodic Benefit Cost (Credit) $20 $(1) $70 $94
==== ===== ==== ====
The following table provides the net periodic benefit cost (credit) for
the plans by the following AEP registrant subsidiaries for the three and
six months ended June 30, 2004 and 2003:
Three Months ended June 30, 2004 and 2003:
- -----------------------------------------
U.S. U.S. Other
Pension Plans Postretirement Benefit Plans
----------------- ----------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
APCo $313 $(1,299) $6,430 $8,371
CSPCo (409) (1,350) 2,763 3,671
I&M 1,112 (201) 4,315 5,749
KPCo 143 (140) 741 1,011
OPCo (34) (1,656) 4,907 7,036
PSO 684 (72) 2,112 2,471
SWEPCo 888 254 2,100 2,566
TCC 728 (32) 2,536 3,237
TNC 332 153 1,070 1,469
Six Months ended June 30, 2004 and 2003:
- ---------------------------------------
U.S. U.S. Other
Pension Plans Postretirement Benefit Plans
----------------- ----------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
APCo $635 $(2,600) $12,860 $16,809
CSPCo (813) (2,700) 5,525 7,342
I&M 2,230 (404) 8,630 11,499
KPCo 287 (282) 1,481 2,021
OPCo (62) (3,312) 9,813 14,072
PSO 1,397 (146) 4,224 4,942
SWEPCo 1,802 508 4,200 5,132
TCC 1,494 (62) 5,072 6,475
TNC 676 304 2,140 2,937
9. BUSINESS SEGMENTS
-----------------
All of AEP's registrant subsidiaries have one reportable segment. The
one reportable segment is a vertically integrated electricity
generation, transmission and distribution business except AEGCo, an
electricity generation business. All of the registrants' other
activities are insignificant. The registrant subsidiaries' operations
are managed on an integrated basis because of the substantial impact of
bundled cost-based rates and regulatory oversight on the business
process, cost structures and operating results.
10. FINANCING ACTIVITIES
--------------------
Long-term debt and other securities issued and retired during the first
six months of 2004 were:
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in thousands) (%)
Issuances:
- ---------
CSPCo Installment Purchase Contracts $43,695 Variable 2038
OPCo Financing Obligation 6,080 5.77 2024
PSO Installment Purchase Contracts 33,700 Variable 2014
PSO Senior Unsecured Notes 50,000 4.70 2009
SWEPCo Installment Purchase Contracts 53,500 Variable 2019
SWEPCo Installment Purchase Contracts 41,135 Variable 2011
SWEPCo Financing Obligation 14,226 5.77 2024
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in thousands) (%)
Retirements:
- -----------
APCo First Mortgage Bonds 45,000 7.125 2024
APCo Installment Purchase Contracts 40,000 5.45 2019
CSPCo First Mortgage Bonds 11,000 7.60 2024
CSPCo Installment Purchase Contracts 43,695 6.25 2020
I&M First Mortgage Bonds 30,000 7.20 2024
I&M First Mortgage Bonds 25,000 7.50 2024
OPCo Installment Purchase Contracts 50,000 6.85 2022
OPCo Notes Payable 1,500 6.27 2009
OPCo Notes Payable 2,927 6.81 2008
OPCo First Mortgage Bonds 10,000 7.30 2024
OPCo Senior Unsecured Notes 140,000 7.375 2038
PSO Notes Payable to Trust 77,320 8.00 2037
PSO Installment Purchase Contracts 33,700 4.875 2014
SWEPCo Installment Purchase Contracts 53,500 7.60 2019
SWEPCo Installment Purchase Contracts 12,290 6.90 2004
SWEPCo Installment Purchase Contracts 12,170 6.00 2008
SWEPCo Installment Purchase Contracts 17,125 8.20 2011
SWEPCo First Mortgage Bonds 80,000 6.875 2025
SWEPCo First Mortgage Bonds 40,000 7.75 2004
SWEPCo Notes Payable 3,415 4.47 2011
SWEPCo Notes Payable 1,500 Variable 2008
TCC First Mortgage Bonds 6,195 6.625 2005
TCC Securitization Bonds 28,809 3.54 2005
TNC First Mortgage Bonds 24,036 6.125 2004
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in thousands) (%)
Defeasance:
- ----------
TCC First Mortgage Bonds $27,400 (a) 7.25 2004
TCC First Mortgage Bonds 65,763 (a) 6.625 2005
TCC First Mortgage Bonds 18,581 (a) 7.125 2008
(a) Trust fund assets for defeasance of First Mortgage Bonds of $103
million are included in Other Cash Deposits and $22 million in Bond
Defeasance Funds in TCC's Consolidated Balance Sheets at June 30, 2004.
Trust fund assets are restricted for exclusive use in retiring the First
Mortgage Bonds.
In addition to the transactions reported in the table above, the
following table lists intercompany issuances and retirements of debt due to AEP:
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in thousands) (%)
Issuances:
- ---------
KPCo Notes Payable $20,000 5.25 2015
OPCo Notes Payable 200,000 5.25 2015
Retirements:
- -----------
None.
Lines of Credit - AEP System
- ----------------------------
The AEP System uses a corporate borrowing program to meet the short-term
borrowing needs of its subsidiaries. The corporate borrowing program
includes a utility money pool, which funds the utility subsidiaries and
a non-utility money pool, which funds the majority of the non-utility
subsidiaries. In addition, the AEP System also funds, as direct
borrowers, the short-term debt requirements of other subsidiaries that
are not participants in the non-utility money pool for regulatory or
operational reasons. The AEP System Corporate Borrowing Program operates
in accordance with the terms and conditions outlined by the SEC. AEP has
authority from the SEC through March 31, 2006 for short-term borrowings
sufficient to fund the utility money pool and the non-utility money pool
as well as its own requirements in an amount not to exceed $7.2 billion.
Utility money pool participants include AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC (domestic utility companies). Our
previous order grating borrowing authority to our utilities listed below
expired on June 30 2004. Through June 30, 2004, we had not exceeded our
authority under the previous order. The following are the SEC authorized
limits for short-term borrowings for the domestic utility companies as
of July 1, 2004:
Authorized
----------
(in millions)
AEP Generating Company $125
AEP Texas Central Company 600
AEP Texas North Company 250
Appalachian Power Company 600
Columbus Southern Power Company 150
Indiana Michigan Power Company 500
Kentucky Power Company 200
Ohio Power Company 600
Public Service Company of Oklahoma 300
Southwestern Electric Power Company 350
REGISTRANT SUBSIDIARIES' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
----------------------------------------------------------------------
The following is a combined presentation of certain components of the
registrant subsidiaries' management's discussion and analysis. The
information in this section completes the information necessary for
management's discussion and analysis of financial condition and results
of operations and is meant to be read with (i) Management's Financial
Discussion and Analysis, (ii) financial statements, and (iii) footnotes
of each individual registrant. The Registrants' Combined Management's
Discussion and Analysis section of the 2003 Annual Report should be read
in conjunction with this report.
Significant Factors
- -------------------
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 "Registrants' Combined Management's Discussion and
Analysis" section of the 2003 Annual Report.
In November 2003, the FERC preliminarily found that certain AEP
subsidiaries must fulfill their 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 AEP subsidiaries 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, KPCo 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, APCo 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 the 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
- ----------
AEP subsidiaries continue to be involved in various litigation matters
as described in the "Significant Factors - Litigation" section of
Registrants' Combined Management's Discussion and Analysis in the 2003
Annual Report. The 2003 Annual Report should be read in conjunction with
this report in order to understand other litigation matters that did not
have significant changes in status since the issuance of the 2003 Annual
Report, but may have a material impact on future results of operations,
cash flows and financial condition. Other matters described in the 2003
Annual Report that did not have significant changes during the first six
months of 2004, that should be read in order to gain a full
understanding of the current litigation include disclosure related to
Potential Uninsured Losses.
Federal EPA Complaint and Notice of Violation
- ---------------------------------------------
See discussion of New Source Review Litigation under "Environmental Matters".
Enron Bankruptcy
- ----------------
In 2002, certain subsidiaries of AEP filed claims against Enron and its
subsidiaries in the Enron bankruptcy proceeding pending in the U.S.
Bankruptcy Court for the Southern District of New York. At the date of
Enron's bankruptcy, certain subsidiaries of AEP had open trading
contracts and trading accounts receivables and payables with Enron. In
addition, on June 1, 2001, AEP purchased Houston Pipe Line Company (HPL)
from Enron. Various HPL related contingencies and indemnities from Enron
remained unsettled at the date of Enron's bankruptcy.
Commodity trading settlement disputes - In September 2003, Enron filed a
complaint in the Bankruptcy Court against AEPES challenging AEP's
offsetting of receivables and payables and related collateral across
various Enron entities and seeking payment of approximately $125 million
plus interest in connection with gas related trading transactions. AEP
has asserted its right to offset trading payables owed to various Enron
entities against trading receivables due to several AEP subsidiaries.
The parties are currently in non-binding court-sponsored mediation.
In December 2003, Enron filed a complaint in the Bankruptcy Court
against AEPSC seeking approximately $93 million plus interest in
connection with a transaction for the sale and purchase of physical
power among Enron, AEP and Allegheny Energy Supply, LLC during November
2001. Enron's claim seeks to unwind the effects of the transaction. AEP
believes it has several defenses to the claims in the action being
brought by Enron. The parties are currently in non-binding
court-sponsored mediation.
Enron bankruptcy summary - The amounts expensed in prior years in
connection with the Enron bankruptcy were based on an analysis of
contracts where AEP and Enron entities are counterparties, the
offsetting of receivables and payables, the application of deposits from
Enron entities and management's analysis of the HPL-related purchase
contingencies and indemnifications. As noted above, Enron has challenged
the offsetting of receivables and payables. Management is unable to
predict the outcome of these lawsuits or their impact on 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 AEP and four of its subsidiaries, including
TCC and TNC, certain unaffiliated energy companies and ERCOT. The action
alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made
against TCC and TNC, range from anticompetitive bidding to withholding
power. TCE alleges that these activities resulted in price spikes
requiring TCE to post additional collateral and ultimately forced it
into bankruptcy when it was unable to raise prices to its customers due
to fixed price contracts. The suit alleges over $500 million in damages
for all defendants and seeks recovery of damages, exemplary damages and
court costs. Two additional parties, Utility Choice, LLC and Cirro
Energy Corporation, have sought leave to intervene as plaintiffs
asserting similar claims. AEP and its subsidiaries filed a Motion to
Dismiss in September 2003. In February 2004, TCE filed an amended
complaint. AEP and its subsidiaries filed a Motion to Dismiss the
amended complaint. In June 2004, the Court dismissed all claims against
AEP and its subsidiaries. TCE has appealed the trial court's decision to
the United States Court of Appeals for the Fifth Circuit.
Energy Market Investigations
- ----------------------------
AEP and other energy market participants received data requests,
subpoenas and requests for information from the FERC, the SEC, the PUCT,
the U.S. Commodity Futures Trading Commission (CFTC), the U.S.
Department of Justice and the California attorney general during 2002.
Management responded to the inquiries and provided the requested
information and has continued to respond to supplemental data requests
in 2003 and 2004.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES
in federal district court in Columbus, Ohio. The CFTC alleges that AEP
and AEPES provided false or misleading information about market
conditions and prices of natural gas in an attempt to manipulate the
price of natural gas in violation of the Commodity Exchange Act. The
CFTC seeks civil penalties, restitution and disgorgement of benefits. 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. AEP 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, AEP 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
Counsel on behalf of two special interest groups. The actions allege
that carbon dioxide emissions from power generation facilities
constitute a public nuisance under federal common law due to impacts
associated with global warming, and seek injunctive relief in the form
of specific emission reduction commitments from the defendants.
Management believes the actions are without merit and intends to
vigorously defend against the claims.
Environmental Matters
- ---------------------
As discussed in the 2003 Annual Report, there are emerging environmental
control requirements that management expects will result in substantial
capital investments and operational costs. The sources of these future
requirements include:
o Legislative and regulatory proposals to adopt stringent
controls on sulfur dioxide (SO2), nitrogen oxide (NOx) and
mercury emissions from coal-fired power plants,
o New Clean Water Act rules to reduce the impacts of water intake
structures on aquatic species at certain of our power plants, and
o Possible future requirements to reduce carbon dioxide emissions to
address concerns about global climatic change.
This discussion updates certain events occurring in 2004. You should
also read the "Significant Factors - Environmental Matters" section
within Registrants' Combined Management's Discussion and Analysis in the
2003 Annual Report for a complete description of all material
environmental matters affecting us, including, but not limited to, (1)
the current air quality regulatory framework, (2) estimated air quality
environmental investments, (3) Superfund and state remediation, (4)
global climate change, and (5) costs for spent nuclear fuel disposal and
decommissioning.
Future Reduction Requirements for SO2, NOx, and Mercury
- -------------------------------------------------------
In 1997, the Federal EPA adopted new, more stringent national ambient
air quality standards for fine particulate matter and ground-level
ozone. The Federal EPA is in the process of developing final
designations for fine particulate matter non-attainment areas. The
Federal EPA finalized designations for ozone non-attainment areas on
April 15, 2004. On the same day, the Administrator of the Federal EPA
signed a final rule establishing the elements that must be included in
state implementation plans (SIPs) to achieve the new standards, and
setting deadlines ranging from 2008 to 2015 for achieving compliance
with the final standard, based on the severity of non-attainment. All or
parts of 474 counties are affected by this new rule, including many
urban areas in the Eastern United States.
The Federal EPA identified SO2 and NOx emissions as precursors to the
formation of fine particulate matter. NOx emissions are also identified
as a precursor to the formation of ground-level ozone. As a result,
requirements for future reductions in emissions of NOx and SO2 from the
AEP System's generating units are highly probable. In addition, the
Federal EPA proposed a set of options for future mercury controls at
coal-fired power plants.
Regulatory Emissions Reductions
- -------------------------------
On January 30, 2004, the Federal EPA published two proposed rules that
would collectively require reductions of approximately 70% each in
emissions of SO2, NOx and mercury from coal-fired electric generating
units by 2015 (2018 for mercury). This initiative has two major
components:
o The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to
reduce SO2 and NOx emissions across the eastern half of the
United States (29 states and the District of Columbia) and
make progress toward attainment of the new fine particulate
matter and ground-level ozone national ambient air quality
standards. These reductions could also satisfy these states'
obligations to make reasonable progress towards the national
visibility goal under the regional haze program.
o The Federal EPA proposed to regulate mercury emissions from coal-fired
electric generating units.
The interstate air quality rule would require affected states to
include, in their SIPs, a program to reduce NOx and SO2 emissions from
coal-fired electric utility units. SO2 and NOx emissions would be
reduced in two phases, which would be implemented through a
cap-and-trade program. Regional SO2 emissions would be reduced to 3.9
million tons by 2010 and to 2.7 million tons by 2015. Regional NOx
emissions would be reduced to 1.6 million tons by 2010 and to 1.3
million tons by 2015. Rules to implement the SO2 and NOx trading
programs were proposed on June 10, 2004.
On April 15, 2004, the Federal EPA Administrator signed a proposed rule
detailing how states should analyze and include "Best Available
Retrofit" requirements for individual facilities in their SIPs to
address regional haze. The guidance applies to facilities built between
1962 and 1977 that emit more than 250 tons per year of certain regulated
pollutants in specific industrial categories, including utility boilers.
The Federal EPA included an alternative "Best Available Retrofit"
program based on emissions budgeting and trading programs. For utility
units that are affected by the CAIR, described above, the Federal EPA
proposed that participation in the trading program under the CAIR would
satisfy any applicable "Best Available Retrofit" requirements. However,
the guidance preserves the ability of a state to require site-specific
installation of pollution control equipment through the SIP for purposes
of abating regional haze.
To control and reduce mercury emissions, the Federal EPA published two
alternative proposals. The first option requires the installation of
maximum achievable control technology (MACT) on a site-specific basis.
Mercury emissions would be reduced from 48 tons to approximately 34 tons
by 2008. The Federal EPA believes, and the industry concurs, that there
are no commercially available mercury control technologies in the
marketplace today that can achieve the MACT standards for bituminous
coals, but certain units have achieved comparable levels of mercury
reduction by installing conventional SO2 (scrubbers) and NOx (SCR)
emission reduction technologies. The proposed rule imposes significantly
less stringent standards on generating plants that burn sub-bituminous
coal or lignite. The proposed standards for sub-bituminous coals
potentially could be met without installation of mercury control
technologies.
The Federal EPA recommends, and AEP supports, a second mercury emission
reduction option. The second option would permit mercury emission
reductions to be achieved from existing sources through a national
cap-and-trade approach. The cap-and-trade approach would include a
two-phase mercury reduction program for coal-fired utilities. This
approach would coordinate the reduction requirements for mercury with
the SO2 and NOx reduction requirements imposed on the same sources under
the CAIR. Coordination is significantly more cost-effective because
technologies like scrubbers and SCRs, which can be used to comply with
the more stringent SO2 and NOx requirements, have also proven effective
in reducing mercury emissions on certain coal-fired units that burn
bituminous coal. The second option contemplates reducing mercury
emissions from 48 tons to 34 tons by 2010 and to 15 tons by 2018. A
supplemental proposal including unit-specific allocations and a
framework for the emissions budgeting and trading program preferred by
the Federal EPA was published in the Federal Register on March 16, 2004.
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 AEP subsidiaries will invest in
additional conventional pollution control technology on a major portion
of their coal-fired power plants. Finalization of new requirements for
further SO2, NOx and/or mercury emission reductions will result in the
installation of additional scrubbers, SCR systems and/or the
installation of emerging technologies for mercury control.
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 alleged APCo, CSPCo, I&M, OPCo
and other unaffiliated utilities modified certain units at coal-fired
generating plants in violation of the new source review requirements of
the CAA. The Federal EPA filed its complaints against AEP subsidiaries
in U.S. District Court for the Southern District of Ohio. The court also
consolidated a separate lawsuit, initiated by certain special interest
groups, with the Federal EPA case. The alleged modifications relate to
costs that were incurred at the generating units over a 20-year period.
On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in
order to "perfect" its complaint in the pending litigation. The NOV
expands the number of alleged "modifications" undertaken at the Amos,
Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek
plants during scheduled outages on these units from 1979 through the
present. Approximately one-third of the allegations in the NOV are
already contained in allegations made by the states or the special
interest groups in the pending litigation. The Federal EPA is expected
to file a motion to amend its complaint, and, to the extent that motion
seeks to expand the scope of the pending litigation, the AEP
subsidiaries will oppose that motion.
Management is unable to estimate the loss or range of loss related to
any contingent liability the AEP subsidiaries might have for civil
penalties under the CAA proceedings. Management is also unable to
predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be
determined by the Court. If the AEP System companies do not prevail, any
capital and operating costs of additional pollution control equipment
that may be required, as well as any penalties imposed, would adversely
affect future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated rates and
market prices for electricity.
In other pending CAA litigation against unaffiliated utility companies
referenced in the annual report, the petition for certiorari filed with
the Supreme Court in the TVA litigation was denied by the Court on May
3, 2004. In addition, the United States has filed a notice of appeal
with the Fourth Circuit Court of Appeals from the adverse decision in
the Duke case, and a briefing order has been issued by the Court that
will require briefing to be completed by late September 2004.
Clean Water Act Regulation
- --------------------------
On July 9, 2004, the Federal EPA published in the Federal Registrar a
rule pursuant to the Clean Water Act that will require all large
existing, once-through cooled power plants to meet certain performance
standards to reduce the mortality of juvenile and adult fish or other
larger organisms pinned against a plant's cooling water intake screens.
All plants must reduce fish mortality by 80% to 95%. A subset of these
plants that are located on sensitive water bodies will be required to
meet additional performance standards for reducing the number of smaller
organisms passing through the water screens and the cooling system.
These plants must reduce the rate of smaller organisms passing through
the plant by 60% to 90%. Sensitive water bodies are defined as oceans,
estuaries, the Great Lakes, and small rivers with large plants. These
rules will result in additional capital and operation and maintenance
expenses to ensure compliance. The estimated capital cost of compliance
for the AEP System's facilities, based on the Federal EPA's estimates in
the rule, is $193 million. Any capital costs associated with compliance
activities to meet the new performance standards would likely be
incurred during the years 2008 through 2010. Management has not
independently confirmed the accuracy of the Federal EPA's estimate. The
rule has provisions to limit compliance costs. Management may propose
less costly site-specific performance criteria if compliance cost
estimates are significantly greater than the Federal EPA's estimates or
greater than the environmental benefits. The rule also allows for
mitigation (also called restoration measures) if it is less costly and
has equivalent or superior environmental benefits than meeting the
criteria in whole or in part. Several states, electric utilities
(including APCo) and environmental groups appealed certain aspects of
the rule. Management cannot predict the outcome of the appeals. The
following table shows the investment amount per subsidiary.
Estimated
Compliance
Investments
-----------
(in millions)
APCo $21
CSPCo 19
I&M 118
OPCo 31
Other Matters
- -------------
As discussed in the 2003 Annual Report, there are several "Other
Matters" affecting AEP subsidiaries, including FERC's proposed standard
market design and FERC's market power mitigation efforts. There were no
significant changes to the status of FERC's proposed standard market
design. The current status of FERC's market power mitigation efforts is
described below.
FERC Market Power Mitigation
- ----------------------------
A FERC order issued in November 2001 on AEP's triennial market-based
wholesale power rate authorization update required certain mitigation
actions that AEP would need to take for sales/purchases within its
control area and required AEP to post information on its website
regarding its power system's status. As a result of a request for
rehearing filed by AEP and other market participants, FERC issued an
order delaying the effective date of the mitigation plan until after a
planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a
technical conference in January 2004. In April 2004, the FERC issued two
orders concerning utilities' ability to sell wholesale electricity at
market based rates. In the first order, the FERC adopted two new interim
screens for assessing potential generation market power of applicants
for wholesale market based rates, and described additional analyses and
mitigation measures that could be presented if an applicant does not
pass one of these interim screens. AEP and two unaffiliated utilities
were required to submit generation market power analyses within sixty
days of the FERC's order. In July 2004, the FERC issued an order on
rehearing affirming its conclusions in the April order and directing AEP
and two unaffiliated utilities to file generation market power analyses
within 30 days. In the second order, the FERC initiated a rulemaking to
consider whether the FERC's current methodology for determining whether
a public utility should be allowed to sell wholesale electricity at
market-based rates should be modified in any way. We plan to present
evidence to demonstrate that we do not possess market power in geographic
areas where we sell wholesale power.
CONTROLS AND PROCEDURES
-----------------------
During the second quarter of 2004, management, including the principal executive
officer and principal financial officer of AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC (collectively, the Registrants), evaluated the
Registrants' disclosure controls and procedures relating to the recording,
processing, summarization and reporting of information in the Registrants'
periodic reports filed with the SEC. These disclosure controls and procedures
have been designed to ensure that (a) material information relating to the
Registrants is made known to the Registrants' management, including these
officers, by other employees of the Registrants, and (b) this information is
recorded, processed, summarized, evaluated and reported, as applicable, within
the time periods specified in the SEC's rules and forms. The Registrant's
controls and procedures can only provide reasonable, not absolute, assurance
that the above objectives have been met.
As of June 30, 2004, these officers concluded that the disclosure controls and
procedures in place provide reasonable assurance that the disclosure controls
and procedures accomplished their objectives. The Registrants continually
strives to improve its disclosure controls and procedures to enhance the quality
of its financial reporting and to maintain dynamic systems that change as events
warrant.
There have been no changes in the Registrants' internal controls over financial
reporting (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the
Exchange Act) during the second quarter of 2004 that have materially affected,
or are reasonably likely to materially affect, the Registrants' internal control
over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
-----------------
For a discussion of material legal proceedings, see Note 5,
Commitments and Contingencies, incorporated herein by reference.
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities
---------------------------------------------------------------------
The following table provides information about purchases by AEP (or
its publicly-traded subsidiaries) during the quarter ended June 30,
2004 of equity securities that are registered by AEP (or its
publicly-traded subsidiaries) pursuant to Section 12 of the Exchange
Act:
ISSUER PURCHASES OF EQUITY SECURITIES
Maximum Number
(or Approximate
Total Number Dollar Value) of
of Shares Purchased as Shares that May Yet
Part of Publicly Be Purchased
Total Number Average Price Announced Plans Under the Plans
Period of Shares Purchased (1) Paid per Share or Programs or Programs
------ ----------------------- -------------- ---------------------- -------------------
04/01/04 - 04/30/04 - $- - $-
05/01/04 - 05/31/04 5 70.00 - -
06/01/04 - 06/30/04 3 69.00 - -
-- ------- -- ---
Total 8 $69.63 - $-
== ======= == ===
(1) TCC and OPCo repurchased an aggregate of 5 shares of its 4% cumulative preferred stock and 3 shares of its 4.5%
cumulative preferred stock, respectively, in privately-negotiated transactions outside of an announced program.
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
AEP
The annual meeting of shareholders was held in Columbus, Ohio, on April
27, 2004. The holders of shares entitled to vote at the meeting or
their proxies cast votes at the meeting with respect to the following
six matters, as indicated below:
1. Election of eleven directors to hold office until the next
annual meeting and until their successors are duly elected. Each
nominee for director received the votes of shareholders as
follows:
No. of Shares No. of Shares
Voted For Abstaining
------------- -------------
E. R. Brooks 304,880,019 8,450,055
Donald M. Carlton 301,928,439 11,401,635
John P. DesBarres 304,936,922 8,393,152
Robert W. Fri 305,300,688 8,029,386
William R. Howell 305,172,590 8,157,484
Lester A. Hudson, Jr. 300,799,680 12,530,394
Leonard J. Kujawa 301,737,241 11,592,833
Michael G. Morris 300,949,642 12,380,432
Richard L. Sandor 303,225,412 10,104,662
Donald G. Smith 303,120,154 10,209,920
Kathryn D. Sullivan 302,132,773 11,197,301
2. Ratification of the appointment of the firm of Deloitte &
Touche LLP as the independent auditors for 2004. The proposal
was approved by a vote of the shareholders as follows:
Votes FOR 296,126,400
Votes AGAINST 15,883,072
Votes ABSTAINED 1,320,602
Broker NON-VOTES* 0
3. Shareholder proposal submitted by the International Brotherhood
of Electrical Workers' Pension Benefit Fund urging the Board of
Directors to seek shareholder approval of certain future
severance agreements with senior executives. The proposal was
approved by a vote of the shareholders as follows:
Votes FOR 149,622,711
Votes AGAINST 108,314,061
Votes ABSTAINED 5,307,905
Broker NON-VOTES* 50,085,397
4. Shareholder proposal submitted by the AFL-CIO Reserve Fund
urging the Board of Directors to seek shareholder approval of
certain future extraordinary pension benefits for senior
executives. The proposal was disapproved by a vote of the
shareholders as follows:
Votes FOR 73,773,833
Votes AGAINST 184,152,624
Votes ABSTAINED 5,318,220
Broker NON-VOTES* 50,085,397
5. Shareholder proposal submitted by the United Association S&P 500
Fund requesting the Board of Directors and its Audit Committee
adopt a policy that would limit the work performed by the public
accounting firm retained by the Company to "audit" and
"audit-related" services. The proposal was disapproved by a vote
of the shareholders as follows:
Votes FOR 36,206,757
Votes AGAINST 221,661,710
Votes ABSTAINED 5,376,210
Broker NON-VOTES* 50,085,397
6. Shareholder proposal submitted by Mr. Ronald Marsico seeking to
limit the maximum amount of service by any Director, except for
the Chief Executive Officer and the President, to eight terms of
office. The proposal was disapproved by a vote of the
shareholders as follows:
Votes FOR 21,178,705
Votes AGAINST 236,643,469
Votes ABSTAINED 5,422,499
Broker NON-VOTES* 50,085,401
*A non-vote occurs when a nominee holding shares for a
beneficial owner votes on one proposal, but does not vote on
another proposal because the nominee does not have discretionary
voting power and has not received instructions from the
beneficial owner.
APCo
The annual meeting of stockholders was held on April 27, 2004 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes
were cast FOR each of the following nine persons for election as
directors and there were no votes withheld and such persons were
elected directors to hold office for one year or until their
successors are elected and qualify:
Jeffrey D. Cross Robert P. Powers
Henry W. Fayne Thomas V. Shockley, III
Thomas M. Hagan Stephen P. Smith
Michael G. Morris Susan Tomasky
Armando A. Pena
TCC
Pursuant to action by written consent in lieu of an annual meeting
of the sole shareholder dated April 8, 2004, the following nine
persons were elected directors to hold office for one year or until
their successors are elected and qualify:
Jeffrey D. Cross Robert P. Powers
Henry W. Fayne Thomas V. Shockley, III
Thomas M. Hagan Stephen P. Smith
Michael G. Morris Susan Tomasky
Armando A. Pena
I&M
Pursuant to action by written consent in lieu of an annual meeting
of the sole shareholder dated April 27, 2004, the following thirteen
persons were elected directors to hold office for one year or until
their successors are elected and qualify:
Karl G. Boyd Susanne M. Moorman
John E. Ehler Michael G. Morris
Henry W. Fayne Robert P. Powers
Thomas M. Hagan John R. Sampson
Patrick C. Hale Thomas V. Shockley, III
David L. Lahrman Susan Tomasky
Marc E. Lewis
OPCo
The annual meeting of shareholders was held on May 4, 2004 at 1
Riverside Plaza, Columbus, Ohio. At the meeting there were 27,952,473
votes cast FOR each of the following nine persons for election as
directors and there were no votes withheld and such persons were
elected directors to hold office for one year or until their
successors are elected and qualify:
Jeffrey D. Cross Robert P. Powers
Henry W. Fayne Thomas V. Shockley, III
Thomas M. Hagan Stephen P. Smith
Michael G. Morris Susan Tomasky
Armando A. Pena
SWEPCo
Pursuant to action by written consent in lieu of an annual meeting
of the sole shareholder dated April 14, 2004, the following nine
persons were elected directors to hold office for one year or until
their successors are elected and qualify:
Jeffrey D. Cross Robert P. Powers
Henry W. Fayne Thomas V. Shockley, III
Thomas M. Hagan Stephen P. Smith
Michael G. Morris Susan Tomasky
Armando A. Pena
Item 5. Other Information
-----------------
NONE
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
--------
AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
Exhibit 12 - Computation of Consolidated Ratio of Earnings to
Fixed Charges.
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
Exhibit 31.1 - Certification of Chief Executive Officer Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 31.2 - Certification of Chief Financial Officer Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.1 - Certification of Chief Executive Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the
United States Code.
Exhibit 32.2 - Certification of Chief Financial Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the
United States Code.
(b) Reports on Form 8-K:
-------------------
The following reports on Form 8-K were filed during the quarter ended
June 30, 2004.
Company Reporting Date of Report Item Reported
----------------- -------------- -------------
AEP April 27, 2004 Item 7. Financial Statements and Exhibits
Item 9. Regulation FD Disclosure
AEP April 29, 2004 Item 7. Financial Statements and Exhibits
Item 12. Results of Operations and Financial Condition
PSO June 7, 2004 Item 5. Other Events and Regulation FD Disclosure
Item 7. Financial Statements and Exhibits
SIGNATURE
---------
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signature for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/Joseph M. Buonaiuto
----------------------
Joseph M. Buonaiuto
Controller and
Chief Accounting Officer
AEP GENERATING COMPANY
AEP TEXAS CENTRAL COMPANY
AEP TEXAS NORTH COMPANY
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
By: /s/Joseph M. Buonaiuto
----------------------
Joseph M. Buonaiuto
Controller and
Chief Accounting Officer
Date: August 6, 2004