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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended MARCH 31, 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 of the Registrants at Par Value at
April 30, 2004 April 30, 2004
--------------------------------- --------------
AEP Generating Company 1,000 $1,000
AEP Texas Central Company 2,211,678 25
AEP Texas North Company 5,488,560 25
American Electric Power Company, Inc. 395,648,498 6.50
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
March 31, 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 Respective Financial Statements
Registrants' 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 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
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 AEPR.
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 Pool
AEP Power Pool generation and resultant wholesale system sales of the member companies.
AEP West companies PSO, SWEPCo, TCC and TNC.
ALJ Administrative Law Judge.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
Cook Plant The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the
legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
DETM Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE United States Department of Energy.
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 71 Statement of Financial Accounting Standards No. 71,
Accounting for the Effects of Certain Types of Regulation.
----------------------------------------------------------
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.
U.K. The United Kingdom.
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.
o Available sources and costs of 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 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 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 reduce 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
-----------------------------------------------------------------------
RESULTS OF OPERATIONS
- ---------------------
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 plants and third parties
o Investments-Other:
o Coal mining, bulk commodity barging operations 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.
For information on our strategic outlook, see "Management's Financial Discussion
and Analysis of Results of Operations", including "Business Strategy", in our
2003 Annual Report.
American Electric Power Company's consolidated Net Income for the three months
ended March 31, 2004 and 2003 were as follows (Earnings and Average Shares
Outstanding in millions):
2004 2003
-------------------- ----------------------
Earnings EPS Earnings EPS
-------- ----- -------- -----
Utility Operations $299 $0.76 $306 $0.86
Investments - Gas Operations (10) (0.03) (18) (0.05)
Investments - UK Operations - - - -
Investments - Other 11 0.03 20 0.05
All Other* (9) (0.02) (15) (0.04)
----- ------ ----- ------
Income Before Discontinued Operations
and Cumulative Effect of Accounting Changes 291 0.74 293 0.82
Investments - Gas Operations (1) - 3 0.01
Investments - UK Operations (12) (0.04) (40) (0.11)
Investments - Other - - (9) (0.02)
----- ------ ----- ------
Discontinued Operations (13) (0.04) (46) (0.12)
Utility Operations - - 236 0.67
Investments - Gas Operations - - (22) (0.07)
Investments - UK Operations - - (21) (0.06)
----- ------ ----- ------
Cumulative Effect of Accounting Changes - - 193 0.54
----- ------ ----- ------
Total Net Income $278 $0.70 $440 $1.24
===== ====== ===== ======
Average Shares Outstanding 395 356
====== ======
* All Other includes the parent company interest income and expense, as well as other non-allocated costs.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Income Before Discontinued Operations and Cumulative Effect of Accounting
Changes decreased $2 million to $291 million in 2004 compared to 2003. Net
Income for 2004 of $278 million or $0.70 per share includes a loss, net of
taxes, on discontinued operations of $13 million. Net Income for 2003 of $440
million or $1.24 per share includes a loss, net of taxes, from discontinued
operations of $46 million and a favorable impact of $193 million, net of tax,
from implementing accounting pronouncements related to risk management contracts
and asset retirement obligations.
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 our coal procurement and
transportation operations. We continue to seek buyers for our UK Operations.
LIG's operations include 2,000 miles of intrastate gas pipelines, gas processing
facilities and a 9 billion cubic feet natural gas storage facility. The pipeline
and processing operations of LIG were sold in April 2004 (see Note 7).
Average shares outstanding increased to 395 million in 2004 from 356 million in
2003 due to a common stock issuance in March 2003. The additional average shares
outstanding decreased our 2004 earnings per share by $0.08.
Our results of operations are discussed below according to our operating
segments.
Utility Operations
- ------------------
Summary of Selected Sales Data
For Utility Operations
For the Three Months Ended March 31, 2004 and 2003
2004 2003
------- -------
Energy Summary (in millions of KWH)
Retail
Residential 13,442 13,513
Commercial 8,827 8,891
Industrial 12,434 12,612
Miscellaneous 743 695
------- -------
Total 35,446 35,711
------- -------
Wholesale 19,341 20,359
------- -------
2004 2003
------- -------
Weather Summary (in degree days)
Eastern Region
Actual - Heating 1,864 2,028
Normal - Heating* 1,806 **
Actual - Cooling 3 1
Normal - Cooling* 3 **
Western Region
Actual - Heating 553 684
Normal - Heating* 634 **
Actual - Cooling 56 24
Normal - Cooling* 49 **
*Normal Heating/Cooling represents the 30-year average of degree days.
**Not meaningful.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Income from Utility Operations, before the 2003 $236 million cumulative effect
of accounting changes, decreased $7 million to $299 million in 2004. A $32
million increase in gross margins and a $12 million decrease in other expenses
offset a $51 million increase in operations and maintenance expense.
Our gross margin, defined as utility revenues net of related fuel and purchased
power, increased as follows:
o Residential demand decreased slightly over the prior year as a
consequence of milder weather, while slightly lower commercial and
industrial demand resulted from the continued slow economic recovery in
our regions. Our reduced demand was offset by increases in fuel
recoveries, coming from lower 2004 fuel disallowances in Texas when
compared to 2003. The net impact of lower demand and higher fuel
recoveries was a slightly improved retail energy contribution to
earnings.
o Beginning in 2004, we no longer recognize revenues for excess cost over
market-based stranded costs, resulting in $56 million of lower
regulatory deferrals for excess cost over market-based stranded costs
which reduced earnings. For the years 2003 and 2002, we recognized the
non-cash provisions for stranded cost recovery in Texas as a regulatory
asset for the difference between the actual price received from the
state-mandated auction of 15% of generation capacity and the earlier
estimate of market price derived by a PUCT model.
o Margins from off-system sales for 2004 were $50 million better than in 2003
due to favorable power and coal optimization activity.
Utility operating expenses increased as follows:
o Maintenance and Other Operation expense increased $51 million due to
the timing of tree trimming activity and planned plant outages in 2004
compared to 2003. These increases were offset, in part, by the changes
in accounting treatment for our Gavin Scrubber Leases.
o Depreciation and Amortization expense increased $15 million due, in
part, to the change in our accounting treatment for Gavin Scrubber
Leases when we adopted the provisions of a new accounting
interpretation (FIN 46) in the second half of 2003. The accounting
change caused similar offsetting decreases in Maintenance and Other
Operation expenses.
Investments - Gas Operations
- ----------------------------
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Our $10 million loss from our Gas Operations before discontinued operations and
cumulative effect of accounting changes compares with an $18 million loss
recorded in the first quarter of 2003. Gross margins improved year-over-year,
excluding the effect of one time accounting adjustments, and operating expenses
have decreased as a result of the reduction in our trading activities.
Investments - UK Operations
- ---------------------------
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Our UK Operations (all classified as Discontinued Operations) incurred a loss of
$12 million for 2004 compared with a loss of $40 million in 2003, before the
cumulative effect of accounting changes. During late 2003, we concluded that the
UK Operations were not part of our core business and we began actively marketing
our investment. As a result, we impaired certain U.K. investments in the fourth
quarter of 2003 based on bids received from interested buyers.
Our UK Operations gross margins from generation increased $45 million in 2004,
reflecting the improvement in wholesale electricity prices in the U.K. but were
offset by a $49 million increase in losses from coal and freight contracts.
These losses resulted from adverse price movements during the quarter. The
decrease in the overall UK Operations loss was driven by an $8 million decrease
in trading expenses, a $5 million decrease in depreciation from the cessation of
plant depreciation, a $12 million decrease in interest expense and a $7 million
decrease in tax expense.
Investments - Other
- -------------------
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Income before discontinued operations and cumulative effect of accounting
changes from our Other Investments segment decreased by $9 million to $11
million in 2004. The decrease was primarily due to a $26 million nonrecurring
gain from the sale of Mutual Energy recorded in 2003. This was offset by a $4
million increase in results at AEP Coal and an increase in income in our
independent power producer and wind farm investments. The majority of the AEP
Coal assets were sold in April 2004 (see Note 7).
All Other
- ---------
Our parent company's 2004 expenses decreased $6 million over 2003 primarily from
lower interest costs due to decreased debt at the parent level and reduced
reliance on short-term borrowings.
FINANCIAL CONDITION
- -------------------
We measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Capitalization
- -------------- March, 31 December 31,
2004 2003
---- ----
Common Equity 36.2% 35.1%
Preferred Stock 0.6 0.6
Long-term Debt, including amounts due within one year 61.7 62.8
Short-term Debt 1.5 1.5
------ ------
Total Capitalization 100.0% 100.0%
====== ======
In addition to the impact of our $901 million in cash flows from operations and
a reduction in dividends paid, we reduced long-term debt by $334 million. We
also improved our percentage of common equity outstanding to total
capitalization, in part through the issuance of $10 million of new common
equity. As a consequence of the capital changes during the quarter, we improved
our ratio of debt to total capital.
In April 2004, we retired approximately $76.2 million of long-term debt using
the net cash proceeds from the sale of LIG Pipeline assets.
Liquidity
- ---------
Liquidity, or access to cash, is an important factor in determining our
financial stability due to volatility in wholesale power prices and the effects
of credit rating downgrades. 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 March 31, 2004, of approximately $3.6
billion as illustrated in the table below.
Amount Maturity
------------- --------
(in millions)
Commercial Paper Backup:
Lines of Credit (a) $ 750 May 2004
Lines of Credit 1,000 May 2005
Lines of Credit 750 May 2006
Euro Revolving Credit
Facility 183 October 2004
Letter of Credit Facility 200 September 2006
-------
Total 2,883
Available Cash and Temporary
Investments 1,071 (b)
-------
Total Liquidity Sources 3,954
Less: AEP Commercial Paper
Outstanding 284 (c)
Letters of Credit
Outstanding 101
-------
Net Available Liquidity at March 31, 2004 $3,569
=======
(a) In early May 2004, we renewed the existing $750 million line of credit expiring in May 2004 as a 3 year, $1 billion facility.
(b) Available Cash and Temporary Investments of $1,071 million and $182 million of other cash on hand make up the $1,253 million
Cash and Cash Equivalents balance on our Consolidated Balance Sheet at March 31, 2004.
(c) Amount does not include JMG Funding LP commercial paper outstanding in the amount of $27 million. This commercial paper is
specifically associated with the Gavin scrubber lease and does not reduce available liquidity to AEP.
Debt Covenants
- --------------
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
March 31, 2004, this percentage was 57.6%. Non-performance of these covenants
may result in an event of default under these credit agreements. At March 31,
2004, we were in compliance with the covenants contained in 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 commercial paper backup 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, AEP 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.
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. If we receive a downgrade in our credit ratings by one of
the nationally recognized rating agencies listed below, our borrowing costs
would increase. The rating agencies currently have AEP and our rated
subsidiaries on stable outlook. Current ratings for AEP 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
Cash Flow
- ---------
Our cash flows are a major factor in managing and maintaining our liquidity
strength.
Three Months Ended March 31,
2004 2003
---- ----
(in millions)
Cash and Cash Equivalents at Beginning of Period $1,182 $1,199
------- -------
Net Cash Flows From Operating Activities 901 762
Net Cash Flows Used For Investing Activities (254) (1,001)
Net Cash Flows From (Used For) Financing Activities (576) 754
------- -------
Net Increase in Cash and Cash Equivalents 71 515
------- -------
Cash and Cash Equivalents at End of Period $1,253 $1,714
======= =======
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 other subsidiaries that
are not participants in the non-utility money pool for regulatory or operational
reasons.
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. Money pool and
external borrowings may not exceed SEC authorized limits.
Operating Activities
- --------------------
Three Months Ended March 31,
2004 2003
---- ----
(in millions)
Net Income $278 $440
Plus: Discontinued Operations 13 46
----- -----
Income from Continuing Operations 291 486
Noncash Items Included in Earnings 208 73
Changes in Assets and Liabilities 402 203
----- -----
Net Cash Flows From Operating Activities $901 $762
===== =====
2004 Operating Cash Flow
- ------------------------
Our cash flows from operating activities were $901 million for the first quarter
2004. We produced income from continuing operations of $291 million during the
period. Income from continuing operations for the period included noncash
expense items of $267 million for depreciation, amortization and deferred taxes.
In addition, there is a current period impact for a net $59 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 those 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
changes in accounts receivable and accounts payable of $83 million, and an
increase in the balance of accrued taxes of $189 million.
2003 Operating Cash Flow
- ------------------------
Income from continuing operations was $486 million for the first quarter of
2003. Income from continuing operations for the period included noncash items of
$247 million for depreciation, amortization, and deferred taxes, and $193
million related to the cumulative effect of an accounting change. There was a
current period impact for a net $19 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 $56 million, deposits associated with risk management
activities of $201 million, and seasonal increases in accrued taxes of $206
million.
Investing Activities
- --------------------
Three Months Ended March 31,
2004 2003
---- ----
(in millions)
Construction Expenditures $(309) $(292)
Investment in Discontinued Operations, net 7 (749)
Proceeds from Sale of Assets 40 35
Other 8 5
------ --------
Net Cash Flows Used for Investing Activities $(254) $(1,001)
====== ========
Our cash flows used for investing activities decreased $747 million from the
same period in the prior year primarily due to investments made in our U.K.
operations during the first quarter of 2003 that did not recur during the first
quarter of 2004.
Financing Activities
- --------------------
Three Months Ended March 31,
2004 2003
---- ----
(in millions)
Issuances of Common Stock $10 $1,143
Issuances/Retirements of Debt, net (444) (186)
Retirement of Preferred Stock (4) -
Dividends (138) (203)
------ -------
Net Cash Flows From (Used for)
Financing Activities $(576) $754
====== =======
Our cash flow for financing activities in 2004 decreased $1.3 billion from the
$754 million net cash inflow recorded in the first quarter of 2003. During the
first quarter of 2003 we issued $1,143 million of common stock and subsequent to
the first quarter of 2003, we reduced our dividend. This compares to only $10
million of cash proceeds from the issuance of common in the first quarter of
2004.
During the first three months of 2004, we retired approximately $414 million of
long-term debt, excluding $25 million related to an asset sale, and decreased
our short-term debt by $103 million. We also issued approximately $73 million of
long-term debt including $54 million of pollution control bonds (installment
purchase contracts) at SWEPCo. These activities were supported by the generation
of $901 million in cash flow from operations. See Note 10 "Financing Activities"
for further information regarding issuances and retirements of debt instruments
during the first quarter of 2004.
Off-balance Sheet Arrangements
- ------------------------------
We enter into off-balance sheet arrangements for various reasons including
accelerating cash collections, reducing operational expenses and spreading risk
of loss to third parties. Our 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 plans limit 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) for Juniper to develop,
construct, own and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. The Facility is a "qualifying cogeneration facility" for purposes of PURPA.
Commercial operation of the Facility as required by the agreements between
Juniper, AEP and The Dow Chemical Company (Dow) was achieved on March 18, 2004.
The initial term of the lease commenced on March 18, 2004, and we may extend the
lease term for up to 30 years. The 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.
Juniper arranged to finance the Facility with debt financing up to $494 million
and equity up to $31 million from investors with no relationship to AEP or any
of AEP's subsidiaries.
At March 31, 2004, Juniper's acquisition costs for the Facility totaled $516
million, and we estimate total costs for the completed Facility to be
approximately $525 million. For the 30-year extended lease term, the majority of
base lease rental is a variable rate obligation indexed to three-month LIBOR
(1.11% as of March 31, 2004). Consequently, as market interest rates increase,
the base rental payments under the lease will also increase. Juniper is
currently planning to refinance by June 30, 2004. The Facility is collateral for
the debt obligation of Juniper. An additional rental prepayment (up to $396
million) may be due on June 30, 2004 unless Juniper has refinanced its present
debt financing on a long-term basis. At March 31, 2004 and December 31, 2003, we
reflected $396 million as long-term debt due within one year. Our maximum
required cash payment as a result of our financing transaction with Juniper is
$396 million as well as interest payments during the lease term. Due to the
treatment of the Facility as a financing of an owned asset, the recorded
liability of $516 million is greater than our maximum possible cash payment
obligation to Juniper.
Dow will use a portion of the energy produced by the Facility and sell the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of such
excess energy from Dow. 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 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.
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).
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
7.8% 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) announcing
in March 2004 that we had signed an agreement to sell TCC's remaining generating
assets, including eight natural gas plants, one coal-fired plant and one hydro
plant for approximately $430 million, subject to closing adjustments. Subject to
certain co-owners' rights of first refusal, we expect all of our announced sales
to close before the end of 2004, after receiving appropriate regulatory
approvals and clearances. We will file with the Public Utility Commission of
Texas to recover net stranded costs associated with each of the sales pursuant
to Texas restructuring legislation.
AEP Coal
- --------
In 2003, as a result of management's decision to exit our non-core business, 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. The sale closed in April
2004 and the effect of the sale on second quarter of 2004 results of operations
should not be 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 our interest
in Houston Pipe Line, which is part of our Investments-Gas Operations segment.
In February 2004, we signed an agreement to sell the pipeline assets of LIG. The
sale was completed in early April 2004 and the impact on results of operations
in the second quarter of 2004 is not expected to be significant. We continue to
market the remaining LIG gas storage assets.
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 IPP investments for a sales price of $156 million,
subject to closing adjustments. We expect the transaction will result in a
pre-tax gain of approximately $100 million (primarily related to the two
facilities in Florida which were not impaired) when the sale is expected to
close later in 2004.
UK Operations
- -------------
During the fourth quarter of 2003, we engaged an advisor for the disposition of
our U.K business. In connection with the evaluation of this business, we
recorded a pre-tax charge of $577.4 million during the fourth quarter of 2003
based on indications of value received from potential buyers. We continue to
work towards identifying a buyer for these assets and plan to dispose of them
during 2004.
Other
- -----
We continue to have periodic discussions with various parties on business
alternatives for certain of our other non-core investments.
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 upon 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 has not issued a final order
in this matter.
In April 2004, we reached an agreement with interveners to settle the RTO issues
in Kentucky. The KPSC is expected to consider the settlement agreement in May
2004.
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 quarter 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) Texas Commercial
Energy, LLP Lawsuit.
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 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
Houston Pipe Line Company (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 (10.5 BCF and
55 BCF as described in the preceeding 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. 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 they have 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. Management is unable to predict the outcome of this
lawsuit or its impact on results of operations, cash flows and financial
condition.
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, Enron, in connection with BOA's dispute, 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. Management is unable to predict the outcome of these proceedings or
the impact on results of operations, cash flows or financial condition.
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. Management is unable to predict the outcome of this
lawsuit or its impact on our results of operations, cash flows or financial
condition.
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. Management is unable to predict the
outcome of this lawsuit or its impact on our results of operations, cash flows
or financial condition.
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 this lawsuit or its impact on our results of operations, cash flows or
financial condition.
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. The case is in the initial pleading stage with our
response to the complaint currently due on May 18, 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 results of operations.
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 are responding to that request.
Management cannot predict whether these governmental agencies will take further
action with respect to these matters.
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 new environmental control
requirements that we expect will result in substantial capital investments and
operational costs through 2010. 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 and adds an estimate of
future capital expenditures for the Clean Water Act rule. 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 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 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 and ground-level ozone 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 an interstate air quality rule for reducing SO2 and
NOx emissions across the eastern half of the United States (29 states and
the District of Columbia) to address attainment of the 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 have not yet
been proposed.
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 January 24, 2004 Interstate
Air Quality Rule (IAQR), described above, the Federal EPA proposed that
participation in the trading program under the IAQR would satisfy any applicable
"Best Available Retrofit" requirements.
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, which standards 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 proposed interstate air quality rule. 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 highly effective in reducing mercury emissions on certain
coal-fired units that burn bituminous coal. The second option contemplates
reducing mercury emissions from 48 million tons to 34 million tons by 2010 and
to 15 million 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. Comments on both the initial proposal and the supplemental notice are due
on or before June 29, 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.
We are unable to estimate the loss or range of loss related to the contingent
liability 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.
Clean Water Act Regulation
- --------------------------
On February 16, 2004, the Federal EPA signed 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 capital cost of
compliance for our 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. 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.
Critical Accounting Policies
- ----------------------------
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. AEP and two
unaffiliated utilities were required to submit generation market power analyses
within sixty days of the FERC's order. 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. Management is unable to
predict the outcome of these actions by the FERC or their affect on future
results of operations and cash flows.
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 which 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, Chief Credit
Officer, V.P. 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)
Three Months Ended March 31, 2004
Investments Investments
Utility Gas UK
Operations Operations Operations 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) (34) 23 149 138
Fair Value of New Contracts When Entered
Into During the Period (b) - - - -
Net Option Premiums Paid/(Received) (c) 12 18 2 32
Change in Fair Value Due to Valuation Methodology
Changes - - - -
Changes in Fair Value of Risk Management
Contracts (d) 51 (20) (26) 5
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) (1) - - (1)
----- ---- ------ -----
Total MTM Risk Management Contract Net Assets
(Liabilities) at March 31, 2004 $314 $26 $(121) 219
===== ==== ======
Net Cash Flow Hedge Contracts (f) (103)
Net Risk Management Liabilities
Held for Sale, included in the totals above (g) 178
-----
Ending Net Risk Management Assets at March 31, 2004 $294
=====
(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) "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 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 in detail
within the following pages.
(g) See Note 7 for discussion of Assets Held for Sale.
Detail on MTM Risk Management Contract Net Assets (Liabilities)
As of March 31, 2004
Investments Investments
Utility Gas UK
Operations Operations Operations Consolidated
---------- ----------- ----------- ------------
(in millions)
Current Assets $568 $267 $297 $1,132
Non Current Assets 398 174 120 692
------ ------ ------ --------
Total Assets $966 $441 $417 $1,824
------ ------ ------ --------
Current Liabilities $(449) $(232) $(404) $(1,085)
Non Current Liabilities (203) (183) (134) (520)
------ ------ ------ --------
Total Liabilities $(652) $(415) $(538) $(1,605)
------ ------ ------ --------
Total Net Assets (Liabilities),
excluding Cash Flow Hedges $314 $26 $(121) $219
====== ====== ====== ========
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2004
Risk
Management Cash Flow Assets Held
Contracts* Hedges for Sale Consolidated
---------- --------- ----------- ------------
(in millions)
Current Assets $1,132 $25 $(297) $860
Non Current Assets 692 1 (120) 573
-------- ------ ------ --------
Total Assets $1,824 $26 $(417) $1,433
-------- ------ ------ --------
Current Liabilities $(1,085) $(116) $461 $(740)
Non Current Liabilities (520) (13) 134 (399)
-------- ------ ------ --------
Total Liabilities $(1,605) $(129) $595 $(1,139)
-------- ------ ------ --------
Total Net Assets (Liabilities) $219 $(103) $178 $294
======== ====== ====== ========
*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 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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in millions)
Utility Operations:
Prices Actively Quoted - Exchange Traded
Contracts $(22) $(13) $(1) $3 $- $- $(33)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 102 74 22 7 4 - 209
Prices Based on Models and Other
Valuation Methods (b) 11 20 14 26 23 44 138
----- ----- ----- ---- ---- ---- ------
Total $91 $81 $35 $36 $27 $44 $314
----- ----- ----- ---- ---- ---- ------
Investments - Gas Operations:
Prices Actively Quoted - Exchange
Traded Contracts $60 $29 $(1) $1 $- $- $89
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (17) 13 - - - - (4)
Prices Based on Models and Other
Valuation Methods (b) - (38) (9) (3) (3) (6) (59)
----- ----- ----- ---- ---- ---- ------
Total $43 $4 $(10) $(2) $(3) $(6) $26
----- ----- ----- ---- ---- ---- ------
Investments - UK Operations:
Prices Actively Quoted - Exchange
Traded Contracts $- $- $- $- $- $- $-
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (38) (82) (1) - - - (121)
Prices Based on Models and Other
Valuation Methods (b) - - - - - - -
----- ----- ----- ---- ---- ---- ------
Total $(38) $(82) $(1) $- $- $- $(121)
----- ----- ----- ---- ---- ---- ------
Consolidated:
Prices Actively Quoted - Exchange
Traded Contracts $38 $16 $(2) $4 $- $- $56
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 47 5 21 7 4 - 84
Prices Based on Models and Other
Valuation Methods (b) 11 (18) 5 23 20 38 79
----- ----- ----- ---- ---- ---- ------
Total $96 $3 $24 $34 $24 $38 $219
===== ===== ===== ==== ==== ==== ======
(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 March 31, 2004
Domestic Transaction Class Market/Region Tenor
-------- ----------------- ------------- -----
(in months)
Natural Gas Futures NYMEX Henry Hub 69
Physical Forwards Gulf Coast, Texas 12
Swaps Gas East - Northeast, Mid-continent
Gulf Coast, Texas 12
Swaps Gas West - Rocky Mountains,
West Coast 12
Exchange Option Volatility NYMEX/Henry Hub 12
Power Futures PJM 33
Physical Forwards Cinergy 33
Physical Forwards PJM 33
Physical Forwards NYPP 33
Physical Forwards NEPOOL 21
Physical Forwards ERCOT 21
Physical Forwards TVA -
Physical Forwards Com Ed 21
Physical Forwards Entergy 21
Physical Forwards PV, NP15, SP15, MidC, Mead 57
Peak Power Volatility
(Options) Cinergy 12
Peak Power Volatility
(Options) PJM 12
Crude Oil Swaps West Texas Intermediate 33
Emissions Credits SO2 21
Coal Physical Forwards PRB, NYMEX, CSX 33
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 fair value hedges and 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, the table does
not provide a full picture of our hedging activity. 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 March 31, 2004.
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging 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 Income (Loss)
On the Balance Sheet as of March 31, 2004
Portion Expected to
Accumulated Other be Reclassified to
Comprehensive Income Earnings During the
(Loss) After Tax (a) Next 12 Months (b)
-------------------- --------------------
(in millions)
Power and Gas $(42) $(36)
Foreign Currency (18) (18)
Interest Rate (12) (5)
----- -----
Total $(72) $(59)
===== =====
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2004
Power Foreign
and Gas Currency Interest Rate Consolidated
------- -------- ------------- ------------
(in millions)
Beginning Balance,
December 31, 2003 $(65) $(20) $(9) $(94)
Changes in Fair Value (c) (30) (6) (4) (40)
Reclassifications from AOCI to Net
Income (d) 53 8 1 62
----- ----- ----- -----
Ending Balance,
March 31, 2004 $(42) $(18) $(12) $(72)
===== ===== ===== =====
(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 independently assess 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 $45 million, we believe that credit exposure with
any one counterparty is not material to our financial condition at March 31,
2004. At March 31, 2004, our credit exposure net of credit collateral to sub
investment grade counterparties was approximately 20% expressed in terms of net
MTM assets and net receivables. The increase in non-investment grade credit
quality was largely due to an increase to coal exposures related to domestic MTM
coal transactions and coal and freight exposures related to our U.K.
investments. These increases were driven by the continued high levels of prices
for coal and freight. As of March 31, 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 $912 $102 $810 - $-
Split Rating 24 - 24 3 18
Non-Investment Grade 364 199 165 4 117
No External Ratings:
Internal Investment
Grade 319 5 314 2 115
Internal Non-Investment
Grade 160 41 119 3 100
------- ----- ------- --- -----
Total $1,779 $347 $1,432 12 $350
======= ===== ======= === =====
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. 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 megawatt hours 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 March 31, 2004
Remainder
2004 2005 2006
---- ---- ----
Estimated Plant Output Hedged 88% 91% 91%
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 March 31, 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
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
--------------------------- ----------------------------
(in millions) (in millions)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$2 $19 $10 $2 $11 $19 $7 $4
The 2004 first quarter High VaR was due to the wind-down of the London risk
management activities. These activities were concluded by the end of the
quarter.
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
March 31, 2004 2004 Year-to-Date 2004 Year-to-Date 2004
-------------- ------------ ------------------ -----------------
(in millions)
95% Confidence Level, Ten-Day
Holding Period $9 $38 $73 $8
99% Confidence Level, One-Day
Holding Period $4 $16 $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 $0.843 billion at March
31, 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 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 Months Ended March 31, 2004 and 2003
(in millions, except per-share amounts)
(Unaudited)
2004 2003
---- ----
REVENUES
-------------------------------------------------------------------
Utility Operations $2,579 $2,687
Gas Operations 652 933
Other 110 165
------- -------
TOTAL 3,341 3,785
------- -------
EXPENSES
-------------------------------------------------------------------
Fuel for Electric Generation 688 730
Purchased Electricity for Resale 83 156
Purchased Gas for Resale 585 878
Maintenance and Other Operation 876 894
Depreciation and Amortization 317 309
Taxes Other Than Income Taxes 184 188
------- -------
TOTAL 2,733 3,155
------- -------
OPERATING INCOME 608 630
------- -------
Other Income (Expense), Net 49 66
------- -------
INTEREST AND OTHER CAPITAL CHARGES
-------------------------------------------------------------------
Interest 199 192
Preferred Stock Dividend Requirements of Subsidiaries 2 3
Minority Interest in Finance Subsidiary - 9
------- -------
TOTAL 201 204
------- -------
INCOME BEFORE INCOME TAXES 456 492
Income Taxes 165 199
------- -------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF
ACCOUNTING CHANGES 291 293
DISCONTINUED OPERATIONS (Net of Tax) (13) (46)
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (Net of Tax)
-------------------------------------------------------------------
Accounting for Risk Management Contracts - (49)
Asset Retirement Obligations - 242
------- -------
NET INCOME $278 $440
======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 395 356
======= =======
EARNINGS PER SHARE
-------------------------------------------------------------------
Income Before Discontinued Operations and Cumulative Effect of
Accounting Changes $0.74 $0.82
Discontinued Operations (0.04) (0.12)
Cumulative Effect of Accounting Changes - 0.54
------- -------
TOTAL EARNINGS PER SHARE (BASIC AND DILUTED) $0.70 $1.24
======= =======
CASH DIVIDENDS PAID PER SHARE $0.35 $0.60
======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in millions)
CURRENT ASSETS
-------------------------------------------------------------------
Cash and Cash Equivalents $1,253 $1,182
Accounts Receivable:
Customers 1,101 1,155
Accrued Unbilled Revenues 473 596
Miscellaneous 76 83
Allowance for Uncollectible Accounts (129) (124)
-------- --------
Total Receivables 1,521 1,710
-------- --------
Fuel, Materials and Supplies 961 991
Risk Management Assets 860 766
Margin Deposits 93 119
Other 142 129
-------- --------
TOTAL 4,830 4,897
-------- --------
PROPERTY, PLANT AND EQUIPMENT
-------------------------------------------------------------------
Electric:
Production 15,389 15,112
Transmission 6,198 6,130
Distribution 9,991 9,902
Other (including gas, coal mining and nuclear fuel) 3,599 3,584
Construction Work in Progress 1,047 1,305
-------- --------
TOTAL 36,224 36,033
Less: Accumulated Depreciation and Amortization 14,169 14,004
-------- --------
TOTAL-NET 22,055 22,029
-------- --------
OTHER NON-CURRENT ASSETS
-------------------------------------------------------------------
Regulatory Assets 3,549 3,548
Securitized Transition Assets 679 689
Spent Nuclear Fuel and Decommissioning Trusts 1,036 982
Investments in Power and Distribution Projects 216 212
Goodwill 78 78
Long-term Risk Management Assets 573 494
Other 832 733
-------- --------
TOTAL 6,963 6,736
-------- --------
Assets Held for Sale 2,387 2,916
Assets of Discontinued Operations - 166
TOTAL ASSETS $36,235 $36,744
======== ========
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in millions)
CURRENT LIABILITIES
-----------------------------------------------------------------
Accounts Payable $1,246 $1,337
Short-term Debt 326 326
Long-term Debt Due Within One Year* 1,904 1,779
Risk Management Liabilities 740 631
Accrued Taxes 811 620
Accrued Interest 197 207
Customer Deposits 422 379
Other 666 703
-------- --------
TOTAL 6,312 5,982
-------- --------
NON-CURRENT LIABILITIES
-----------------------------------------------------------------
Long-term Debt* 11,863 12,322
Long-term Risk Management Liabilities 399 335
Deferred Income Taxes 4,057 3,957
Regulatory Liabilities and Deferred Investment Tax Credits 2,333 2,259
Asset Retirement Obligations and Nuclear Decommissioning Trusts 664 640
Employee Benefits and Pension Obligations 691 667
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 173 176
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption 72 76
Deferred Credits and Other 498 519
-------- --------
TOTAL 20,750 20,951
-------- --------
Liabilities Held for Sale 1,041 1,773
Liabilities of Discontinued Operations - 103
TOTAL LIABILITIES 28,103 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. . . . . . . . . . . . .404,643,133 404,016,413
(8,999,992 shares were held in treasury at March 31, 2004 and December 31, 2003) 2,630 2,626
Paid-in Capital 4,190 4,184
Retained Earnings 1,630 1,490
Accumulated Other Comprehensive Income (Loss) (379) (426)
-------- --------
TOTAL 8,071 7,874
-------- --------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $36,235 $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 Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in millions)
OPERATING ACTIVITIES
-----------------------------------------------------------
Net Income $278 $440
Plus: Discontinued Operations 13 46
------- -------
Income from Continuing Operations 291 486
Adjustments for Noncash Items:
Depreciation and Amortization 317 309
Deferred Income Taxes 49 22
Deferred Investment Tax Credits (9) (7)
Cumulative Effect of Accounting Changes - (193)
Amortization of Deferred Property Taxes (90) (87)
Amortization of Cook Plant Restart Costs - 10
Mark-to-Market of Risk Management Contracts (59) 19
Over/Under Fuel Recovery 15 74
Change in Other Assets (6) (165)
Change in Other Liabilities 84 (28)
Changes in Certain Components of Working Capital
Accounts Receivable, net 180 (867)
Accounts Payable (97) 869
Fuel, Materials and Supplies 29 163
Customer Deposits 43 201
Taxes Accrued 189 206
Interest Accrued (10) 3
Other Current Assets 10 (57)
Other Current Liabilities (35) (196)
------- -------
Net Cash Flows From Operating Activities 901 762
------- -------
INVESTING ACTIVITIES
-----------------------------------------------------------
Construction Expenditures (309) (292)
Investment in Discontinued Operations, net 7 (749)
Proceeds from Sale of Assets 40 35
Other 8 5
------- -------
Net Cash Flows Used For Investing Activities (254) (1,001)
------- -------
FINANCING ACTIVITIES
-----------------------------------------------------------
Issuance of Common Stock 10 1,143
Issuance of Long-term Debt 73 2,498
Change in Short-term Debt, net (103) (2,467)
Retirement of Long-term Debt (414) (217)
Retirement of Preferred Stock (4) -
Dividends Paid on Common Stock (138) (203)
------- -------
Net Cash Flows From (Used For) Financing Activities (576) 754
------- -------
Net Increase in Cash and Cash Equivalents 71 515
Cash and Cash Equivalents at Beginning of Period 1,182 1,199
------- -------
Cash and Cash Equivalents at End of Period $1,253 $1,714
======= =======
Net Increase in Cash and Cash Equivalents from Discontinued Operations $24 $59
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 13 21
------- -------
Cash and Cash Equivalents from Discontinued Operations - End of Period $37 $80
======= =======
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest, net of capitalized amounts, was $200 million and $177 million in 2004 and 2003, respectively. There was
no cash paid for income taxes in 2004 and 2003. Noncash acquisitions under capital leases were $3 million and $0 in 2004 and
2003.
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 Three Months Ended March 31, 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 (203) (203)
Common Stock Expense (35) (35)
Other (15) 2 (13)
-------
TOTAL 7,990
-------
COMPREHENSIVE INCOME
- -------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments 13 13
Cash Flow Hedges (22) (22)
Securities Available for Sale 1 1
Minimum Pension Liability 15 15
NET INCOME 440 440
-------
TOTAL COMPREHENSIVE INCOME 447
---- ------- ------- ------- ------ -------
MARCH 31, 2003 404 $2,626 $4,175 $2,238 $(602) $8,437
==== ======= ======= ======= ====== =======
DECEMBER 31, 2003 404 $2,626 $4,184 $1,490 $(426) $7,874
Issuance of Common Stock 1 4 6 10
Common Stock Dividends (138) (138)
----------
TOTAL 7,746
----------
COMPREHENSIVE INCOME
- -------------------------------------------------------
Other Comprehensive Income, Net of Taxes:
Foreign Currency Translation Adjustments 8 8
Cash Flow Hedges 22 22
Minimum Pension Liability 17 17
NET INCOME 278 278
-------
TOTAL COMPREHENSIVE INCOME 325
---- ------- ------- ------- ------ -------
MARCH 31, 2004 405 $2,630 $4,190 $1,630 $(379) $8,071
==== ======= ======= ======= ====== =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in millions)
TOTAL LONG-TERM DEBT OUTSTANDING
--------------------------------
First Mortgage Bonds $835 $940
Installment Purchase Contracts 1,990 2,026
Notes Payable 1,491 1,518
Senior Unsecured Notes 7,857 7,997
Securitization Bonds 718 746
Notes Payable to Trust 331 331
Equity Unit Senior Notes 345 345
Long-term DOE Obligation (a) 227 226
Other Long-term Debt 21 21
Equity Unit Contract Adjustment Payments 16 19
Unamortized Discount (net) (64) (68)
-------- --------
TOTAL 13,767 14,101
Less Portion Due Within One Year 1,904 1,779
-------- --------
TOTAL LONG-TERM PORTION $11,863 $12,322
======== ========
(a) 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 $269 million and $262 million related to this obligation are
included in Spent Nuclear Fuel and Decommissioning Trusts in the
Consolidated Balance Sheets at March 31, 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 March 31,
2004 2003
---- ----
(in millions)
Other Income:
Interest and Dividend Income $6 $5
Equity Earnings 7 1
Non-operational Revenue 29 28
Gain on Sale of REPs (Mutual Energy Companies) - 39
Other 38 37
---- ----
Total Other Income 80 110
---- ----
Other Expense:
Non-operational Expenses 24 26
Other 7 18
--- ----
Total Other Expense 31 44
---- ----
Total Other Income (Expense), Net $49 $66
==== ====
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):
March 31, December 31,
2004 2003
--------- ------------
Components
- ---------- (in millions)
Foreign Currency Translation Adjustments $118 $110
Unrealized Losses on Securities Available for Sale (1) (1)
Unrealized Losses on Cash Flow Hedges (72) (94)
Minimum Pension Liability (424) (441)
------ ------
Total $(379) $(426)
====== ======
We expect to reclassify approximately $59 million of net losses from cash flow
hedges in Accumulated Other Comprehensive Income (Loss) at March 31, 2004 to Net
Income during the next twelve months at the time the hedged transactions affect
net income. Five years approximates the maximum period over which an exposure to
a variability in future cash flows is hedged. 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
- -------------------------------------------
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 the beginning and ending aggregate carrying
amount of asset retirement obligations:
U.K. Plants,
Wind Mills
Nuclear Ash and Coal
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 13.7 1.5 0.8 16.0
Foreign Currency
Translation - - 0.8 0.8
------- ------ ------ -------
Asset Retirement Obligation
Liability at March 31, 2004
including Held for Sale 784.6 76.9 54.7 916.2
Less Asset Retirement Obligation
Liability Held for Sale:
South Texas Project (222.8) - - (222.8)
U.K. Plants - - (30.0) (30.0)
AEP Coal - - (10.9) (10.9)
------- ------ ------ -------
Asset Retirement Obligation
Liability at March 31, 2004 $561.8 $76.9 $13.8 $652.5
======= ====== ====== =======
Accretion expense is included in Maintenance and Other Operation expense in our
accompanying Consolidated Statements of Operations.
As of March 31, 2004 and December 31, 2003, the fair value of assets that are
legally restricted for purposes of settling the nuclear decommissioning
liabilities totaled $897 million and $845 million, respectively, of which $767
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 $130
million and $125 million as of March 31, 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. 106-1, Accounting and Disclosure Requirements Related
to the Medicare Prescription Drug Improvement and Modernization Act of 2003
- ------------------------------------------------------------------------------
In accordance with FASB Staff Position No. 106-1, in December 2003 we elected to
defer accounting for any effects of the prescription drug subsidy under the
Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act)
until the FASB issues authoritative guidance on the accounting for the federal
subsidy. Our measurements of the accumulated postretirement benefit obligation
and periodic postretirement benefit cost included in these financial statements
do not reflect any potential effects of the Act. We cannot determine what
impact, if any, new authoritative guidance on the accounting for the federal
subsidy may have on our results of operations or financial condition.
Future Accounting Changes
- -------------------------
The Financial Accounting Standards Board's (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 projects related
to accounting for stock compensation, pension plans, property, plant and
equipment, earnings per share calculations 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
proceedings in the FERC and several state jurisdictions. 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 Reconciliations
- ------------------------
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
of July 2000 through December 2001 will be the final fuel reconciliation for
TNC's ERCOT service territory. At December 31, 2001, the deferred under-recovery
balance associated with TNC's ERCOT service area was $27.5 million including
interest. During the reconciliation period, TNC incurred $293.7 million of
eligible fuel costs serving both ERCOT and SPP retail customers. TNC also
requested authority to surcharge its SPP customers for under-recovered fuel
costs as of the end of the reconciliation period. The under-recovery balance at
December 31, 2001 for TNC's service within SPP was $0.7 million including
interest.
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. The remand issues are 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 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.
On December 3, 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 on January 15, 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 February 2002, TNC received a final order from the PUCT in a previous fuel
reconciliation covering the period July 1997 to June 2000 and reflected the
order in its financial statements. This final order was appealed to the Travis
County District Court. In May 2003, the District Court upheld the PUCT's final
order. That order was appealed to the Third Court of Appeals. In March 2004, the
Third Court of Appeals heard oral arguments. A decision is pending.
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 of July 1998 through December
2001. At December 31, 2001, the over-recovery balance for TCC was $63.5 million
including interest. During the reconciliation period, TCC incurred $1.6 billion
of eligible fuel and fuel-related expenses.
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. The over-recovery
balance and the provisions total $163 million including interest at March 31,
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, cash flows and financial condition. 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 SPP. This
reconciliation covers the period of 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 addition, the settlement provides for the deferral
as a regulatory asset of costs of a new lignite mining agreement in excess of a
specified benchmark for lignite at SWEPCo's Dolet Hills Plant. The settlement
provides for recovery of the deferred costs over a period ending in April 2011
as cost savings are realized under the new mining agreement. The settlement also
will allow future recovery of litigation costs associated with the termination
of a previous lignite mining agreement if we achieve future cost savings. 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%. On February 9, 2004, eight
intervening parties filed testimony recommending reductions to TCC's requested
$67 million rate increase. The recommendations range from a decrease in existing
rates of approximately $100 million to an increase in TCC's current rates of
approximately $27 million. The PUCT Staff filed testimony, on February 17, 2004,
recommending reductions to TCC's request of approximately $51 million. TCC's
rebuttal testimony was filed on February 26, 2004. The PUCT held hearings in
March 2004 and is expected to issue a decision in June 2004. Management is
unable to predict the ultimate effect of this proceeding on TCC's rates or its
impact on TCC's 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 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 would adversely impact results of
operations and cash flows.
PSO Fuel and Purchased Power
- ----------------------------
PSO had a $44 million under-recovery of fuel costs resulting from a 2002
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 recovery of the $44 million over an 18-month
period. 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 were inconsistent with the FERC-approved Operating Agreement and
System Integration Agreement and could more than offset the $44 million 2002
allocation. The intervenor and the OCC Staff also believed trading margins were
allocated incorrectly. Under the intervenor's recalculation of margin
allocation, PSO's amount of recoverable fuel would be decreased approximately
$6.8 million for 2000 and $10.7 million for 2001. OCC Staff calculates the 2001
amount at $8.8 million. They also recommend recalculation of fuel for years
subsequent to 2001 using the same methods. Hearings are scheduled to occur in
June 2004. 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 Costs
- -------------------------------
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 $31
million of RTO formation and integration costs and related carrying charges
through March 31, 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 August 2003, the Virginia SCC
filed a request for rehearing of the July 2003 order, arguing that FERC's action
was an infringement on state jurisdiction, and that FERC should not have treated
Alliance RTO startup costs in the same manner as PJM integration costs. On
October 22, 2003, FERC denied the rehearing request.
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 the
deferred RTO 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 at the time
they join PJM. Presently, retail base rates are frozen or capped and cannot be
increased for retail customers of CSPCo, I&M and OPCo. We intend to file an
application with FERC seeking permission to delay the amortization of the
deferred RTO formation/integration costs until they are recoverable from all
users of the transmission system including retail customers. The AEP East
companies are scheduled to join PJM in October 2004, although there are pending
proceedings at the FERC and in Virginia and Kentucky 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. 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 deferred RTO formation/integration costs and project implementation cost
reimbursements, if incurred. If the FERC ultimately decides not to approve a
delay 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. A hearing for this
proceeding is scheduled in July 2004.
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 is expected to
consider the agreement in May.
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
deferral of the costs for future recovery.
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. FERC has not issued a final order in
this matter.
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 July 17, 2003, I&M filed a fuel adjustment clause application requesting
authorization to implement the fixed fuel adjustment charge (fixed pursuant to a
prior settlement of the Cook Nuclear Plant Outage) for electric service for the
billing months of October 2003 through February 2004, and for approval of a new
fuel cost adjustment credit for electric service to be applicable during the
March 2004 billing month. The Cook settlement agreement provided for the fixed
rate to end in February 2004. In another agreement in connection with a planned
corporate separation I&M agreed, contingent on implementing the corporate
separation, to a new freeze conditionally beginning March 2004 and continuing
through December 2007.
On August 27, 2003, the IURC issued an order approving the requested fixed fuel
adjustment charge for October 2003 through February 2004. The order further
stated that certain parties must negotiate the appropriate action on fuel after
March 1, 2004. Negotiations with the parties to determine a resolution of 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 following the resolution of
issues in the corporate separation agreement. The IURC also issued an order that
reopens the corporate separation docket to investigate issues related to the
corporate separation agreement.
Michigan 2004 Fuel Recovery Plan
- --------------------------------
A Michigan Public Service Commission's (MPSC) December 16, 1999 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. In accordance with the settlement, PSCR
Plan cases were not required to be filed through the 2003 plan year. 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 of this case occurred on March 10, 2004 and a MPSC order is
expected during the second half of 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 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 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
for residential and small nonresidential customers and permits a fixed-rate
Competitive Bidding Process for large general service customers and other
customer classes. Customers who do not switch to a competitive generation
provider can choose between the Market Based Standard Service Offer or the
Competitive Bidding Process. Customers who make no choice will be served
pursuant to the Competitive Bidding Process.
On February 9, 2004, CSPCo and OPCo filed their rate stabilization plan with the
PUCO addressing rates following the end of the MDP, which ends December 31,
2005. If approved by the PUCO, rates would be established pursuant to the plan
for the period from January 1, 2006 through December 31, 2008 instead of the
rates discussed in the previous paragraph. The plan is intended to provide rate
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 on June 30, 2004, the fixed increases would be 1.6% for
CSPCo and 5.7% for OPCo. The 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 certain
required expenditures. 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. The
February 2004 filing provides for the continued deferral of customer choice
implementation costs during the rate stabilization plan period. At March 31,
2004, we have incurred $69 million and deferred $29 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 provided the framework and timetable to allow
retail electricity competition for all 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. See 2004 true-up proceeding
discussion below.
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 PROCEEDING
- -----------------------------
A 2004 true-up proceeding will determine the amount and recovery of:
o net stranded generation plant costs and generation-related regulatory
assets (stranded costs),
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 TNC's filing in May 2004 and TCC's filing in September
2004 or 60 days after the completion of the sale of TCC's generation assets, if
later.
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 have elected to use the sale of assets method to determine the
market value of TCC's generation assets for stranded cost purposes. When
completed, the sale of TCC's generation assets will substantially complete the
required separation of generation assets from transmission and distribution
assets. 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.
It is anticipated that any such sale will result in significant stranded costs
for purposes of TCC's 2004 true-up proceeding.
In December 2002, TCC filed a plan of divestiture with the PUCT seeking approval
of a sales process for all of its generation facilities. In March 2003, the PUCT
dismissed TCC's divestiture filing, determining that it was more appropriate to
address allowable valuation methods for the nuclear asset in a rulemaking
proceeding. The PUCT approved a rule, in May 2003, which allows the market value
obtained by selling nuclear assets to be used in determining stranded costs.
Although the PUCT declined to review TCC's proposed sale of assets process, the
PUCT hired a consultant to advise the PUCT and TCC during the sale of TCC's
generation assets. TCC's sale of its generation assets will be subject to a
review in the 2004 true-up proceeding.
In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's
generation capacity in Texas. In order to sell these assets, we anticipate
retiring TCC's first mortgage bonds by making open market purchases or defeasing
the bonds. Bids were received for all of TCC's generation plants. In January
2004, TCC agreed to sell its 7.8% 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% 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, expiring in May and June 2004, to the co-owners of
Oklaunion and STP, respectively. TCC filed for FERC approval of the sales of the
fossil and hydro plants. TCC will request approval of the STP sale from the FERC
during the second quarter of 2004. We have received a notice from a co-owner of
Oklaunion exercising their right of first refusal; therefore, SEC approval will
be required. Approval of the sale of STP from the Nuclear Regulatory Commission
is required. The completion of the sales is expected to occur in 2004, subject
to the rights of first refusal and the necessary approvals required for each
sale. TCC will file its 2004 true-up proceeding with the PUCT after the sale of
the generation assets.
After the 2004 true-up proceeding, TCC may recover stranded costs and other
true-up amounts through transmission and distribution rates as a competition
transition and may seek to issue securitization revenue bonds for its stranded
costs. The cost of the securitization bonds is recovered through transmission
and distribution rates as a separate transition charge. We recorded an
impairment of generation assets of $938 million in December 2003 as a regulatory
asset (see Note 7). The recovery of the regulatory asset will be subject to
review and approval by the PUCT as a stranded cost in the 2004 true-up
proceeding.
Wholesale Capacity Auction True-up
- ----------------------------------
Texas Legislation also requires 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. 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. TNC received a written order on March 1, 2004 that established TNC's
unrecovered fuel balance, including interest for the ERCOT service territory, at
$4.6 million. This balance will be included in TNC's 2004 true-up proceeding.
Various parties, including TNC, requested rehearing of the PUCT's order.
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 February 2004, an ALJ issued recommendations finding a $205
million over-recovery in this fuel proceeding. 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 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. 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 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. At March 31, 2004, the
remaining retail clawback regulatory liability was $57 million.
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 and other true-up
amounts, through a non-bypassable competition transition charge in the regulated
T&D rates. TCC may also seek to securitize certain of the approved stranded
plant costs and regulatory assets that were not previously recovered through the
non-bypassable transition charge. The annual costs of securitization are
recovered through a non-bypassable rate surcharge collected by the T&D utility
over the term of the securitization bonds.
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 regulatory assets,
unrecovered fuel balances, 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 general rate changes
and an opportunity for recovery 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)
merger litigation, (4) shareholder lawsuits, (5) California lawsuits, (6)
Cornerstone lawsuit, (7) Texas Commercial Energy, LLP 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 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 is scheduled for July 2004.
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.
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 the contingent
liability 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.
OPERATIONAL
- -----------
Power Generation Facility
- -------------------------
We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, own and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. The Facility is a "qualifying cogeneration facility" for purposes of PURPA.
Commercial operation of the Facility as required by the agreements between
Juniper, AEP and The Dow Chemical Company (Dow) was achieved on March 18, 2004.
The initial term of the lease commenced on March 18, 2004, and we may extend the
lease term for up to 30 years. The 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.
Juniper arranged to finance the Facility with debt financing up to $494 million
and equity up to $31 million from investors with no relationship to AEP or any
of AEP's subsidiaries.
At March 31, 2004, Juniper's acquisition costs for the Facility totaled $516
million, and we estimate total costs for the completed Facility to be
approximately $525 million. For the 30-year extended lease term, the majority of
base lease rental is a variable rate obligation indexed to three-month LIBOR
(1.11% as of March 31, 2004). Consequently, as market interest rates increase,
the base rental payments under the lease will also increase. Juniper is
currently planning to refinance by June 30, 2004. The Facility is collateral for
the debt obligation of Juniper. An additional rental prepayment (up to $396
million) may be due on June 30, 2004 unless Juniper has refinanced its present
debt financing on a long-term basis. At March 31, 2004 and December 31, 2003, we
reflected $396 million as long-term debt due within one year. Our maximum
required cash payment as a result of our financing transaction with Juniper is
$396 million as well as interest payments during the lease term. Due to the
treatment of the Facility as a financing of an owned asset, the recorded
liability of $516 million is greater than our maximum possible cash payment
obligation to Juniper.
Dow will use a portion of the energy produced by the Facility and sell the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of such
excess energy from Dow. 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 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.
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 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
Houston Pipe Line Company (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 (10.5 BCF and
55 BCF as described in the preceeding 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. 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 they have 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. Management is unable to predict the outcome of this
lawsuit or its impact on results of operations, cash flows and financial
condition.
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, Enron, in connection with BOA's dispute, 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. Management is unable to predict the outcome of these proceedings or
the impact on results of operations, cash flows or financial condition.
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. Management is unable to predict the outcome of this
lawsuit or its impact on our results of operations, cash flows or financial
condition.
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. Management is unable to predict the
outcome of this lawsuit or its impact on our results of operations, cash flows
or financial condition.
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 this lawsuit or its impact on our results of operations, cash flows or
financial condition.
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. The case is in the initial pleading stage with our
response to the complaint currently due on May 18, 2004. Although management is
unable to predict the outcome of this case, it is not expected to have a
material effect on results of operations due to a provision recorded in December
2003.
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 are responding to that request.
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. AEP and two
unaffiliated utilities were required to submit generation market power analyses
within sixty days of the FERC's order. 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. Management is unable to
predict the outcome of these actions by the FERC or their affect on future
results of operations and cash flows.
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 March 31, 2004, the maximum future payments for
all the LOCs are approximately $322 million with maturities ranging from April
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 Fort Lupton, an IPP 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.
We have guaranteed 50% of a security deposit for gas transmission as well as 50%
of a Power Purchase Agreement (PPA) of Orange Cogeneration (Orange), an IPP of
which we are a 50% owner. In the event Orange fails to make payments in
accordance with agreements for gas transmission, we have a maximum future
payment exposure of approximately $1 million, which expires June 2023. In the
event Orange is unable to perform under its PPA agreement, we have a maximum
future payment exposure of approximately $1 million, which expires June 2016. We
will be released from this guarantee upon the anticipated sale of this IPP. See
Note 7 regarding the sale of IPPs, of which Orange Cogeneration is included.
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 (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 guaranteed 50% of the required debt service reserve for Polk Power
Partners, an IPP of which CSW Energy owns 50%. In the event that Polk Power does
not make the required debt payments, AEP Utilities has a maximum future payment
exposure of approximately $5 million, which expires July 2010. We will be
released from this guarantee upon the anticipated sale of this IPP. See Note 7
regarding the sale of the IPPs, of which Polk is included.
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 March 31, 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.
INDEMNIFICATIONS AND OTHER GUARANTEES
- -------------------------------------
Contracts
- ---------
We entered into several 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, 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 quarter 2004, we entered into several sale agreements. These sale
agreements include indemnifications with a maximum exposure of approximately
$129 million. There are no material liabilities recorded for any
indemnifications entered into during 2003 or the first quarter 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 March 31, 2004, the maximum potential loss for these
lease agreements was approximately $29 million 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 March 31, 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
--------------------------------------------------------------
DISPOSITIONS 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 on March 2, 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 ANNOUNCED DURING FIRST QUARTER 2004
- ------------------------------------------------
During the first quarter of 2004 we announced the following dispositions
expected to close later this year:
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.
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.
Oklaunion Power Station
-----------------------
In January 2004, we signed an agreement to sell TCC's 7.8 percent share of
Oklaunion Power Station for approximately $43 million, subject to closing
adjustments. The planned sale is expected to close in June 2004, subject
to the co-owners' decisions on their rights of first refusal. We have
received notice from a co-owner of their decision to exercise their right
of first refusal.
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. We expect the sale to close in
the second half of 2004, subject to the co-owners' decisions on their
rights of first refusal. We do not expect the sale of this asset to have a
significant effect on our results of operations.
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 for approximately
$430 million, subject to closing adjustments. We expect the sale to close
in mid-2004, subject to various regulatory approvals and clearances.
LIG Pipeline and its Subsidiaries (Investments - Gas Operations segment)
- ------------------------------------------------------------------------
In February 2004, we signed an agreement to sell 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 these LIG Pipeline
Company assets for $76.2 million was completed in April 2004. The effect of the
sale is not expected to have a significant effect on our results of operations
during second quarter 2004. See Louisiana Intrastate Gas (LIG) under
Discontinued Operations for additional information.
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). 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 two of the 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.
On March 10, 2004, we entered into an agreement to sell the four domestic IPP
investments for a sales price of $156 million. We expect the transaction will
result in a pre-tax gain of approximately $100 million when the sale is expected
to close later in 2004. This gain will be generated primarily from the sale of
the two Florida IPPs which were not impaired.
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 $10.8 million in future
reclamation liability. The sale closed in April 2004 and the effect of the sale
on second quarter of 2004 results of operations should not be significant.
The assets and liabilities of AEP Coal that are held for sale have been
included in Assets and Liabilities Held for Sale in our Consolidated Balance
Sheets at March 31, 2004 and December 31, 2003.
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 in 2004 and 2003. Results of operations of these
businesses have been reclassified for the three months ended March 31, 2004 and
2003, as shown in the following table:
Pushan U.K.
Power Generation
Eastex Plant LIG Plants Total
------ ------ --- ---------- -----
(in millions)
2004 Revenue $ - $10 $160 $41 $211
2004 Pretax Income (Loss) - - (1) (19) (20)
2004 Income (Loss) After-Tax - - (1) (12) (13)
2003 Revenue 31 15 203 51 300
2003 Pretax Income (Loss) (14) - 3 (40) (51)
2003 Income (Loss) After-Tax (9) - 3 (40) (46)
Assets and liabilities of discontinued operations have been reclassified as
follows:
Pushan Power
Plant
------------
(in millions)
As of December 31, 2003
Current Assets $24
Property, Plant and Equipment, Net 142
-----
Total Assets of Discontinued Operations $166
=====
Current Liabilities $26
Long-term Debt 20
Deferred Credits and Other 57
-----
Total Liabilities of Discontinued Operations $103
=====
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)
- ---------------------------------------------------------------------
After announcing during 2003 that we would be divesting our non-core assets we
began actively marketing LIG with the help of an investment advisor. 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 the pipeline portion of LIG. The sale was completed
during early April of 2004 and the impact on results of operations in the second
quarter of 2004 is not expected to be significant (see LIG Pipeline and its
Subsidiaries in Dispositions Announced During First Quarter 2004 for additional
information). Management continues its efforts to market the remaining gas
storage assets. The assets and liabilities of LIG are classified as held for
sale 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.
U.K. Generation Plants (Investments - UK Operations segment)
- ------------------------------------------------------------
In December 2001, we acquired two coal-fired generation plants (U.K. Generation)
in the U.K. for a cash payment of $942.3 million and assumption of certain
liabilities. Subsequently and continuing through 2002, wholesale U.K. electric
power prices declined sharply as a result of domestic over-capacity and static
demand. External industry forecasts and our own projections made during the
fourth quarter of 2002 indicated that this situation may extend many years into
the future. As a result, the U.K. Generation fixed asset carrying value at
year-end 2002 was substantially impaired. A December 2002 probability-weighted
discounted cash flow analysis of the fair value of our U.K. Generation indicated
a 2002 pre-tax impairment loss of $548.7 million ($414 million after-tax). This
impairment loss is included in 2002 Discontinued Operations on our Consolidated
Statements of Operations.
In the fourth quarter of 2003, the U.K. generation plants were determined to be
non-core assets and management engaged an investment advisor to assist in
determining the best methodology to exit the U.K. business. 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 that has 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. We
anticipate the sale of the U.K. Generation plants during 2004.
ASSETS HELD FOR SALE
- --------------------
The assets and liabilities of the entities held for sale at March 31, 2004 and
December 31, 2003 are as follows:
U.K. Generation
March 31, 2004 Plants AEP Coal Texas Plants LIG Total
-------------- --------------- -------- ------------ ----- -----
Assets: (in millions)
Current Risk Management Assets $297 $- $- $- $297
Other Current Assets 504 9 56 51 620
Property, Plant and Equipment, Net 101 11 799 167 1,078
Regulatory Assets - - 48 - 48
Decommissioning Trusts - - 130 - 130
Goodwill - - - 15 15
Long-term Risk Management Assets 120 - - - 120
Other 70 - - 9 79
------- ---- ------- ----- -------
Total Assets Held for Sale $1,092 $20 $1,033 $242 $2,387
======= ==== ======= ===== =======
Liabilities:
Current Risk Management Liabilities $449 $- $- $12 $461
Other Current Liabilities 101 - - 48 149
Long-term Risk Management Liabilities 134 - - - 134
Regulatory Liabilities - - 9 - 9
Asset Retirement Obligations 30 11 223 - 264
Employee Benefits and Pension Obligations 12 - - - 12
Deferred Credits and Other 1 - - 11 12
------- ---- ------- ----- -------
Total Liabilities Held for Sale $727 $11 $232 $71 $1,041
======= ==== ======= ===== =======
U.K.
Generation Texas
December 31, 2003 Plants AEP Coal Plants LIG Total
------------------ ---------- -------- ------ --- -----
(in millions)
Assets:
Current Risk Management Assets $560 $- $- $- $560
Other Current Assets 685 6 57 50 798
Property, Plant and Equipment, Net 99 13 797 171 1,080
Regulatory Assets - - 49 - 49
Decommissioning Trusts - - 125 - 125
Goodwill - - - 15 15
Long-term Risk Management Assets 274 - - - 274
Other 6 - - 9 15
------- ---- ------- ----- -------
Total Assets Held for Sale $1,624 $19 $1,028 $245 $2,916
======= ==== ======= ===== =======
Liabilities:
Current Risk Management
Liabilities $767 $- $- $15 $782
Other Current Liabilities 221 - - 46 267
Long-term
Risk Management Liabilities 435 - - - 435
Regulatory Liabilities - - 9 - 9
Asset Retirement Obligations 29 11 219 - 259
Employee Benefits and Pension
Obligations 12 - - - 12
Deferred Credits and Other - 3 - 6 9
------- ---- ------- ----- -------
Total Liabilities Held for Sale $1,464 $14 $228 $67 $1,773
======= ==== ======= ===== =======
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 months ended March 31, 2004
and 2003:
U.S.
U.S. Other Postretirement
Pension Plans Benefit Plans
------------------------ ------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Service Cost $22 $20 $11 $11
Interest Cost 57 58 33 32
Expected Return on Plan Assets (73) (79) (21) (16)
Amortization of Transition
(Asset) Obligation - (2) 7 7
Amortization of Net Actuarial Loss 4 2 12 13
---- ---- ---- ----
Net Periodic Benefit Cost (Credit) $10 $(1) $42 $47
==== ==== ==== ====
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 plants and third parties
Investments - Other
- -------------------
o Coal mining, bulk commodity barging operations 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
months ended March 31, 2004 and 2003 and balance sheet information as of March
31, 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
---------- ---------- ---------- ----- ------ ----------- ------------
2004 (in millions)
- ----
Revenues from:
External Customers $2,579 $652 $- $110 $- $- $3,341
Other Operating Segments 292 24 - 33 2 (351) -
Discontinued Operations,
Net of Tax - (1) (12) - - - (13)
Net Income (Loss) 299 (11) (12) 11 (9) - 278
Total Assets 31,044 2,279 978 1,557 13,130 (12,753) 36,235
Assets Held for Sale and
Assets of Discontinued
Operations 1,033 242 1,092 20 - - 2,387
* 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
---------- ---------- ---------- ----- ------ ----------- ------------
2003 (in millions)
- ----
Revenues from:
External Customers $2,687 $933 $- $165 $- $- $3,785
Other Operating Segments - 44 - 13 - (57) -
Discontinued Operations,
Net of Tax - 3 (40) (9) - - (46)
Cumulative Effect of
Accounting Changes,
Net of Tax 236 (22) (21) - - - 193
Net Income (Loss) 542 (37) (61) 11 (15) - 440
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 1,033 240 1,624 185 - - 3,082
* 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 issuances and retirements during the first
three months of 2004 are shown in the table below. Amounts in total do not
necessarily tie to our statements of cash flows due to rounding and due to
retirements of debt of discontinued operations not included in the amount on our
statements of cash flows.
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in millions) (%)
Issuances:
- ---------
SWEPCo Installment Purchase Contracts $54 Variable 2019
Non-Registrant:
AEP Subsidiary Notes Payable 20 Variable 2009
Principal Interest
Company Type of Debt Amount Rate Due Date
- ------- ------------ --------- -------- --------
(in millions) (%)
Retirements:
- -----------
APCo Installment Purchase Contracts $40 5.45 2019
OPCo Installment Purchase Contracts 50 6.85 2022
OPCo Notes Payable 2 6.27 2009
OPCo Notes Payable 1 6.81 2008
OPCo Senior Unsecured Notes 140 7.375 2038
SWEPCo First Mortgage Bonds 80 6.875 2025
SWEPCo Notes Payable 2 4.47 2011
SWEPCo Notes Payable 1 Variable 2008
TCC First Mortgage Bonds 1 7.125 2005
TCC Securitization Bonds 29 3.54 2005
TNC First Mortgage Bonds 24 6.125 2004
Non-Registrant:
AEP Subsidiary Notes Payable $40 6.73 2004
AEP Subsidiaries Notes Payable and Other Debt 29 Variable 2007-2017
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.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Net Income increased $31 thousand for the first quarter of 2004 compared with
the first quarter of 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.
Operating Income
- ----------------
Operating Income decreased $304 thousand for the first quarter of 2004 compared
with the first quarter of 2003 primarily due to:
o A $5 million decrease in Operating Revenue as a result of decreased
recoverable expenses, primarily Fuel for Electric Generation, in
accordance with the unit power agreements along with a decreased return
on total capital.
o A $4 million increase in Maintenance expense as a result of planned
outages. In the first quarter of 2004, we incurred planned outages
related to boiler inspections.
The decrease in Operating Income was offset by:
o A $9 million decrease in Fuel for Electric Generation expense. This
decrease is primarily due to a 30% decrease in MWH generation as a result of
the planned outages.
Off-balance Sheet Arrangements
- ------------------------------
We enter into off-balance sheet arrangements for various reasons including
accelerating cash collections, reducing operational expenses and spreading risk
of loss to third parties. Our 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 plans limit 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 Narrative
Financial Discussion and Analysis" section of our 2003 Annual Report.
Significant Factors
- -------------------
See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.
Critical Accounting Policies
- ----------------------------
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.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES $55,282 $60,428
-------- --------
OPERATING EXPENSES
- ---------------------------------------------------------
Fuel for Electric Generation 21,398 30,397
Rent - Rockport Plant Unit 2 17,071 17,071
Other Operation 2,490 2,549
Maintenance 5,400 1,651
Depreciation and Amortization 5,734 5,621
Taxes Other Than Income Taxes 944 791
Income Taxes 698 497
-------- --------
TOTAL 53,735 58,577
-------- --------
OPERATING INCOME 1,547 1,851
Nonoperating Income 24 2
Nonoperating Expenses 69 217
Nonoperating Income Tax Credits 857 894
Interest Charges 532 734
-------- --------
NET INCOME $1,827 $1,796
======== ========
STATEMENTS OF RETAINED EARNINGS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $21,441 $18,163
Net Income 1,827 1,796
Cash Dividends Declared 1,262 1,171
-------- --------
BALANCE AT END OF PERIOD $22,006 $18,788
======== ========
The common stock of AEGCo is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -----------------------------------------------------------
Production $648,802 $645,251
General 4,117 4,063
Construction Work in Progress 22,680 24,741
--------- ---------
TOTAL 675,599 674,055
Accumulated Depreciation 350,875 351,062
--------- ---------
TOTAL - NET 324,724 322,993
--------- ---------
OTHER PROPERTY AND INVESTMENTS - Non-Utility Property, Net
119 119
--------- ---------
CURRENT ASSETS
- -----------------------------------------------------------
Accounts Receivable - Affiliated Companies 17,603 24,748
Fuel 23,888 20,139
Materials and Supplies 5,357 5,419
Prepayments 32 -
--------- ---------
TOTAL 46,880 50,306
--------- ---------
DEFERRED DEBITS AND OTHER ASSETS
- -----------------------------------------------------------
Regulatory Assets:
Unamortized Loss on Reacquired Debt 4,674 4,733
Asset Retirement Obligations 975 928
Deferred Property Taxes 2,941 502
Other Deferred Charges 446 464
--------- ---------
TOTAL 9,036 6,627
--------- ---------
TOTAL ASSETS $380,759 $380,045
========= =========
See Notes to Respective Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 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 22,006 21,441
--------- ---------
Total Common Shareholder's Equity 46,440 45,875
Long-term Debt 44,813 44,811
--------- ---------
TOTAL 91,253 90,686
--------- ---------
CURRENT LIABILITIES
- --------------------------------------------------------
Advances from Affiliates 17,745 36,892
Accounts Payable:
General 719 498
Affiliated Companies 15,447 15,911
Taxes Accrued 10,609 6,070
Interest Accrued 456 911
Obligations Under Capital Leases 78 87
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Other 37 -
--------- ---------
TOTAL 68,518 65,332
--------- ---------
DEFERRED CREDITS AND OTHER LIABILITIES
- --------------------------------------------------------
Deferred Income Taxes 24,103 24,329
Regulatory Liabilities:
Asset Removal Costs 27,659 27,822
Deferred Investment Tax Credits 48,755 49,589
SFAS 109 Regulatory Liability, Net 15,074 15,505
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 104,083 105,475
Obligations Under Capital Leases 167 182
Asset Retirement Obligations 1,147 1,125
--------- ---------
TOTAL 220,988 224,027
--------- ---------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $380,759 $380,045
========= =========
See Notes to Respective Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ----------------------------------------------------------------
Net Income $1,827 $1,796
Adjustments to Reconcile Net Income to Net Cash Flows From
Operating Activities:
Depreciation and Amortization 5,734 5,621
Deferred Income Taxes (656) (1,230)
Deferred Investment Tax Credits (834) (835)
Deferred Property Taxes (2,439) (2,329)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (1,392) (1,392)
Changes in Certain Assets and Liabilities:
Accounts Receivable 7,145 (3,129)
Fuel, Materials and Supplies (3,687) 2,309
Accounts Payable (243) (3,348)
Taxes Accrued 4,539 4,967
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets 83 (1,021)
Change in Other Liabilities (583) 554
-------- --------
Net Cash Flows From Operating Activities 27,958 20,427
-------- --------
INVESTING ACTIVITIES
- ----------------------------------------------------------------
Construction Expenditures (7,549) (872)
-------- --------
Net Cash Flows Used For Investing Activities (7,549) (872)
-------- --------
FINANCING ACTIVITIES
- ----------------------------------------------------------------
Change in Advances from Affiliates (19,147) (18,384)
Dividends Paid (1,262) (1,171)
-------- --------
Net Cash Flows Used For Financing Activities (20,409) (19,555)
-------- --------
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 (received) for interest net of capitalized amounts was $921,000 and $1,123,000 and for income taxes was $(218,000) and
$(384,000) in 2004 and 2003, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
The notes to AEGCo's financial statements are combined with the notes to
respective 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 $35 million for 2004 due mainly to the cessation of the
recognition of non-cash earnings related to legislatively mandated capacity
auction sales and regulatory assets established in Texas of $36 million, net of
tax.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $37 million primarily due to:
o Decreased Revenues associated with establishing regulatory assets in
Texas of $56 million in 2003 (see "Texas Restructuring" in Note 4). These
revenues did not continue after 2003.
o Decreased off-system sales, including those to REPs, of $78 million due
mainly to lower KWH sales of 31% and a small decrease in the overall average
price per KWH.
o Decreased revenues from ERCOT for various services, including balancing
energy, which declined $14 million.
o Decreased retail wires revenues of $2 million driven by a 6% decrease in
degree-days, offset in part by a 5% increase in the average price per KWH.
o Decreased Reliability Must Run revenues from ERCOT of $5 million which
includes both fuel recovery and a fixed cost component decrease of $2
million.
o Decreased fees of $6 million for services we provided to others as their
Qualified Scheduling Entity (QSE) due mainly to certain REPs no longer using
TCC as their QSE in 2004.
o Increased Other Operation expenses of $8 million due mainly to $5 million
of increased ERCOT related transmission expense and higher affiliated
ancillary services, as well as an increase of $1 million for emission
allowance expense.
The decrease in Operating Income was partially offset by:
o Increases resulting from risk management activities.
o Net decreases in fuel and purchased electricity on a combined basis of
$72 million. KWH purchased decreased 87% while the cost per KWH decreased
19%. Although the KWH generated increased 23%, fuel costs decreased 4%
attributable mostly to larger amounts of fuel oil burned in 2003.
o Decreased provisions for rate refunds of $14 million due to 2003 Texas fuel
issues (see "TCC Fuel Reconciliation" in Note 3).
o Increased transmission revenue of $10 million due to prior year adjustments
for affiliated OATT and ancillary services resulting from revised data
received from ERCOT for the years 2001-2003.
o Decreased Depreciation and Amortization expense of $17 million due mainly
to the cessation of depreciation on Texas generation plants classified as
"Held For Sale."
o Decreased Income Taxes of $22 million due primarily to a decrease in
pre-tax operating book income.
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $2 million due mainly to risk management
activities.
Interest Charges increased $1 million due primarily to financing activities in
2003 that resulted in an increase in long-term debt outstanding.
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 three months ended March 31, 2004 and 2003 were as follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $65,882 $85,420
-------- --------
Cash flow from (used for):
Operating activities 26,247 50,752
Investing activities (24,122) (21,851)
Financing activities (29,182) (81,525)
-------- --------
Net decrease in cash and cash equivalents (27,057) (52,624)
-------- --------
Cash and cash equivalents at end of period $38,825 $32,796
======== ========
Operating Activities
- --------------------
Cash Flow From Operating Activities in 2004 was $26 million primarily due to Net
Income, as explained above, and Taxes Accrued, offset in part by Deferred
Property Tax, Accounts Payable and Interest Accrued.
Investing Activities
- --------------------
Investing expenditures in 2004 were $24 million due primarily to construction
expenditures focused on improved service reliability projects for transmission
and distribution systems.
Financing Activities
- --------------------
Cash Used For Financing Activities in 2004 reduced Long-term Debt, paid
dividends and was partially offset by Advances to Affiliates.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first three months of 2004
were:
Issuances
---------
None
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $1,055 7.125 2005
Securitization Bonds 28,809 3.540 2005
Significant Factors
- -------------------
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 our
7.8% 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) announcing
in March 2004 that we had signed an agreement to sell our remaining generating
assets, including eight natural gas plants, one coal-fired plant and one hydro
plant for approximately $430 million, subject to closing adjustments. Subject to
certain co-owners' rights of first refusal, we expect all of our announced sales
to close before the end of 2004, after receiving appropriate regulatory
approvals and clearances. We will file with the Public Utility Commission of
Texas to recover net stranded costs associated with each of the sales pursuant
to Texas restructuring legislation.
Critical Accounting Policies
- ----------------------------
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
Three Months Ended March 31, 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) (1,889)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 79
Change in Fair Value Due to Valuation
Methodology Changes -
Changes in Fair Value of Risk Management
Contracts (d) (3,226)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) -
---------
Total MTM Risk Management Contract Net Assets 6,906
Net Cash Flow Hedge Contracts (f) (24,225)
---------
Total MTM Risk Management Contract Net Liabilities
at March 31, 2004 $(17,319)
=========
(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
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).
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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(107) $174 $(7) $61 $- $- $121
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (809) 832 22 - - - 45
Prices Based on Models and Other Valuation
Methods (b) 5,802 (93) 62 156 244 569 6,740
------- ----- ---- ----- ----- ----- -------
Total $4,886 $913 $77 $217 $244 $569 $6,906
======= ===== ==== ===== ===== ===== =======
(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
- ------------------------------------------------------------------------------
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, the table does not provide a full
picture of our hedging activity. In accordance with GAAP, all amounts are
presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $(1,828)
Changes in Fair Value (a) (13,601)
Reclassifications from AOCI to Net
Income (b) (162)
---------
Ending Balance March 31, 2004 $(15,591)
=========
(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 $15,478 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:
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
------------------------- -------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$51 $160 $88 $45 $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 $179 million and $206 million at March 31, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES
- ----------------------------------------------------------
Electric Generation, Transmission and Distribution $268,858 $382,130
Sales to AEP Affiliates 18,130 46,228
--------- ---------
TOTAL 286,988 428,358
--------- ---------
OPERATING EXPENSES
- ----------------------------------------------------------
Fuel for Electric Generation 23,106 27,339
Fuel from Affiliates for Electric Generation 40,199 38,289
Purchased Electricity for Resale 10,086 72,122
Purchased Electricity from AEP Affiliates 4,073 11,562
Other Operation 77,807 69,402
Maintenance 15,404 16,099
Depreciation and Amortization 27,058 44,073
Taxes Other Than Income Taxes 22,057 22,979
Income Taxes 12,006 34,483
--------- ---------
TOTAL 231,796 336,348
--------- ---------
OPERATING INCOME 55,192 92,010
Nonoperating Income 12,102 10,162
Nonoperating Expenses 5,108 5,195
Nonoperating Income Tax Expense (Credit) (20) 558
Interest Charges 33,129 31,982
--------- ---------
Income Before Cumulative Effect of Accounting Change 29,077 64,437
Cumulative Effect of Accounting Change (Net of Tax) - 122
--------- ---------
NET INCOME 29,077 64,559
Preferred Stock Dividend Requirements 60 60
--------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $29,017 $64,499
========= =========
The common stock of TCC is owned by a wholly-owned subsidiary of AEP.
See Notes to Respective Financial Statements 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 Three Months Ended March 31, 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 (30,201) (30,201)
Preferred Stock Dividends (60) (60)
-----------
TOTAL 1,070,873
-----------
COMPREHENSIVE INCOME
- -----------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,018) (1,018)
NET INCOME 64,559 64,559
-----------
TOTAL COMPREHENSIVE INCOME 63,541
-------- --------- ----------- ---------- -----------
MARCH 31, 2003 $55,292 $132,606 $1,020,694 $(74,178) $1,134,414
======== ========= =========== ========== ===========
DECEMBER 31, 2003 $55,292 $132,606 $1,083,023 $(61,872) $1,209,049
Common Stock Dividends (24,000) (24,000)
Preferred Stock Dividends (60) (60)
-----------
TOTAL 1,184,989
-----------
COMPREHENSIVE INCOME
- -----------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (13,763) (13,763)
Minimum Pension Liability (2,466) (2,466)
NET INCOME 29,077 29,077
-----------
TOTAL COMPREHENSIVE INCOME 12,848
-------- --------- ----------- ---------- -----------
MARCH 31, 2004 $55,292 $132,606 $1,088,040 $(78,101) $1,197,837
======== ========= =========== ========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- --------------------------------------------------------
Production $- $-
Transmission 773,318 767,970
Distribution 1,382,806 1,376,761
General 223,695 221,354
Construction Work in Progress 57,858 58,953
----------- -----------
TOTAL 2,437,677 2,425,038
Accumulated Depreciation and Amortization 702,172 695,359
----------- -----------
TOTAL - NET 1,735,505 1,729,679
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- --------------------------------------------------------
Non-Utility Property, Net 1,344 1,302
Other Investments 4,639 4,639
----------- -----------
TOTAL 5,983 5,941
----------- -----------
CURRENT ASSETS
- --------------------------------------------------------
Cash and Cash Equivalents 38,825 65,882
Advances to Affiliates 35,957 60,699
Accounts Receivable:
Customers 151,304 146,630
Affiliated Companies 75,481 78,484
Accrued Unbilled Revenues 20,438 23,077
Allowance for Uncollectible Accounts (1,679) (1,710)
Materials and Supplies 12,520 11,708
Risk Management Assets 11,038 22,051
Margin Deposits 6,417 3,230
Prepayments and Other Current Assets 7,781 6,770
----------- -----------
TOTAL 358,082 416,821
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- --------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 2,712 3,249
Wholesale Capacity Auction True-up 480,000 480,000
Unamortized Loss on Reacquired Debt 8,846 9,086
Designated for Securitization 1,257,967 1,253,289
Deferred Debt - Restructuring 11,861 12,015
Other 126,465 133,913
Securitized Transition Assets 679,397 689,399
Long-term Risk Management Assets 3,226 7,627
Deferred Charges 82,653 55,554
----------- -----------
TOTAL 2,653,127 2,644,132
----------- -----------
Assets Held for Sale - Texas Generation Plants 1,032,807 1,028,134
----------- -----------
TOTAL ASSETS $5,785,504 $5,824,707
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 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 1,088,040 1,083,023
Accumulated Other Comprehensive Income (Loss) (78,101) (61,872)
----------- -----------
Total Common Shareholder's Equity 1,197,837 1,209,049
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,940 5,940
----------- -----------
Total Shareholder's Equity 1,203,777 1,214,989
Long-term Debt 1,773,633 2,053,974
----------- -----------
TOTAL 2,977,410 3,268,963
----------- -----------
CURRENT LIABILITIES
- -----------------------------------------------------------------
Long-term Debt Due Within One Year 488,228 237,651
Accounts Payable:
General 78,632 90,004
Affiliated Companies 71,322 74,209
Customer Deposits 3,491 1,517
Taxes Accrued 98,670 67,018
Interest Accrued 23,248 43,196
Risk Management Liabilities 29,869 17,888
Obligation Under Capital Leases 420 407
Other 17,927 23,248
----------- -----------
TOTAL 811,807 555,138
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- -----------------------------------------------------------------
Deferred Income Taxes 1,233,564 1,244,912
Long-term Risk Management Liabilities 1,714 2,660
Regulatory Liabilities:
Asset Removal Costs 96,606 95,415
Deferred Investment Tax Credits 111,177 112,479
Deferred Fuel Costs 69,026 69,026
Retail Clawback 45,527 45,527
Other 50,082 56,984
Obligation Under Capital Leases 592 636
Deferred Credits and Other 155,844 144,833
----------- -----------
TOTAL 1,764,132 1,772,472
----------- -----------
Liabilities Held for Sale - Texas Generation Plants 232,155 228,134
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $5,785,504 $5,824,707
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ---------------------------------------------------------
Net Income $29,077 $64,559
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change - (122)
Depreciation and Amortization 27,058 44,073
Deferred Income Taxes (3,401) (2,260)
Deferred Investment Tax Credits (1,302) (1,302)
Deferred Property Taxes (33,660) (31,590)
Mark-to-Market of Risk Management Contracts 5,035 5,197
Wholesale Capacity Auction True-up - (56,000)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 937 (66,835)
Fuel, Materials and Supplies (500) 14,833
Accounts Payable (14,259) 39,281
Taxes Accrued 31,652 69,524
Interest Accrued (19,948) (26,285)
Change in Other Assets 2,325 10,116
Change in Other Liabilities 3,233 (12,437)
-------- ---------
Net Cash Flows From Operating Activities 26,247 50,752
-------- ---------
INVESTING ACTIVITIES
- ---------------------------------------------------------
Construction Expenditures (24,105) (21,851)
Other (17) -
-------- ---------
Net Cash Flows Used For Investing Activities (24,122) (21,851)
-------- ---------
FINANCING ACTIVITIES
- ---------------------------------------------------------
Change in Short-term Debt - Affiliates - (650,000)
Issuance of Long-term Debt - 792,028
Retirement of Long-term Debt (29,864) (48,235)
Change in Advances to Affiliates 24,742 (145,057)
Dividends Paid on Common Stock (24,000) (30,201)
Dividends Paid on Cumulative Preferred Stock (60) (60)
-------- ---------
Net Cash Flows Used For Financing Activities (29,182) (81,525)
-------- ---------
Net Decrease in Cash and Cash Equivalents (27,057) (52,624)
Cash and Cash Equivalents at Beginning of Period 65,882 85,420
-------- ---------
Cash and Cash Equivalents at End of Period $38,825 $32,796
======== =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $49,928,000 and $55,483,000 and for income taxes was $(7,567,000)
and $(22,959,000) in 2004 and 2003, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
-------------------------------------------------
The notes to TCC's consolidated financial statements are combined with the notes
to respective 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
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 increased $3 million for 2004 due mainly to reduced provisions for
refunds of $8 million, net of tax, offset in part by the Cumulative Effect of
Accounting Changes of $3 million recorded in 2003.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income increased by $7 million primarily due to:
o Increased Reliability Must Run revenues from ERCOT of $6 million, which
include both fuel recovery and a fixed cost component.
o Decreased fuel and purchased electricity on a combined basis of $21 million.
KWH generation decreased 3%, while the per-unit cost of fuel increased 10%
due primarily to increases in the per-unit cost of natural gas. KWH
purchased declined 53%, and the average cost per KWH purchased decreased 23%.
o Decreased provision for rate refunds of $12 million due to fewer Texas fuel
issues in 2003 (see "TNC Fuel Reconciliation" in Note 3).
o Increased Transmission revenue of $7 million, due mainly to prior year
adjustments for affiliated OATT and ancillary services resulting from revised
data received from ERCOT for the years 2001-2003.
o Reduced Taxes Other Than Income Taxes of $1 million resulting mainly from
lower accrued property taxes.
The increase in Operating Income was partially offset by:
o Decreased off-system sales, including those to retail electric providers,
of $27 million due mainly to lower KWH sales of 31% and a small decrease in
the overall average price per KWH.
o Revenues from ERCOT decreased $5 million for various services, including
balancing energy, due mainly to prior years' adjustments made by ERCOT.
o Reduced wholesale revenues of $1 million due to the loss of several large
wholesale customers whose contracts expired and were not renewed.
o Decreases from risk management activities.
o Increased Income Taxes of $2 million due primarily to an increase in pre-tax
operating book income.
Other Impacts on Earnings
- -------------------------
Interest Charges increased $2 million primarily as a result of refinancing in
the first quarter of 2003, reflecting one month of interest charges as compared
to three months of related interest for 2004.
The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 in 2003.
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 three 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 "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.
Critical Accounting Policies
- ----------------------------
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
Three Months Ended March 31, 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) (662)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 32
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) (1,466)
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) -
--------
Total MTM Risk Management Contract Net Assets 2,524
Net Cash Flow Hedge Contracts (f) (8,098)
--------
Total MTM Risk Management Contract Net Liabilities at March 31, 2004 $(5,574)
========
(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).
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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ---- ---------
(in thousands)
Prices Actually Quoted - Exchange Traded
Contracts $(62) $70 $(3) $24 $- $- $29
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (177) 334 8 - - - 165
Prices Based on Models and Other
Valuation Methods (b) 1,953 (37) 24 63 98 229 2,330
------- ----- ---- ---- ---- ----- -------
Total $1,714 $367 $29 $87 $98 $229 $2,524
======= ===== ==== ==== ==== ===== =======
(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
- --------------------------------------------------------------------------
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, the table does not provide a full
picture of our hedging activity. In accordance with GAAP, all amounts are
presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $(601)
Changes in Fair Value (a) (4,555)
Reclassifications from AOCI to Net
Income (b) (55)
--------
Ending Balance March 31, 2004 $(5,211)
========
(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 $5,166 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:
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
------------------------- -------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$20 $64 $35 $18 $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 $28 million and $33 million at March 31, 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 Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES
- ---------------------------------------------------------
Electric Generation, Transmission and Distribution $88,712 $96,061
Sales to AEP Affiliates 14,718 20,201
-------- --------
TOTAL 103,430 116,262
-------- --------
OPERATING EXPENSES
- ---------------------------------------------------------
Fuel for Electric Generation 7,500 11,461
Fuel from Affiliates for Electric Generation 11,224 6,085
Purchased Electricity for Resale 18,023 24,778
Purchased Electricity from AEP Affiliates 3,532 19,345
Other Operation 20,524 20,619
Maintenance 4,683 4,141
Depreciation and Amortization 9,692 9,532
Taxes Other Than Income Taxes 5,104 6,033
Income Taxes 5,941 4,403
-------- --------
TOTAL 86,223 106,397
-------- --------
OPERATING INCOME 17,207 9,865
Nonoperating Income 13,756 13,471
Nonoperating Expenses 10,936 11,567
Nonoperating Income Tax Expense 894 339
Interest Charges 6,180 4,665
-------- --------
Income Before Cumulative Effect of Accounting Changes 12,953 6,765
Cumulative Effect of Accounting Changes (Net of Tax) - 3,071
-------- --------
NET INCOME 12,953 9,836
Preferred Stock Dividend Requirements 26 26
-------- --------
EARNINGS APPLICABLE TO COMMON STOCK $12,927 $9,810
======== ========
The common stock of TNC is owned by a wholly-owned subsidiary of AEP.
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 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 (26) (26)
---------
TOTAL 175,748
---------
COMPREHENSIVE INCOME
- --------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (421) (421)
Minimum Pension Liability (7) (7)
NET INCOME 9,836 9,836
---------
TOTAL COMPREHENSIVE INCOME 9,408
--------- ------- --------- --------- ---------
MARCH 31, 2003 $137,214 $2,351 $76,782 $(31,191) $185,156
========= ======= ========= ========= =========
DECEMBER 31, 2003 $137,214 $2,351 $125,428 $(26,718) $238,275
Common Stock Dividends (2,000) (2,000)
Preferred Stock Dividends (26) (26)
---------
TOTAL 236,249
---------
COMPREHENSIVE INCOME
- --------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (4,610) (4,610)
NET INCOME 12,953 12,953
---------
TOTAL COMPREHENSIVE INCOME 8,343
--------- ------- --------- --------- ---------
MARCH 31, 2004 $137,214 $2,351 $136,355 $(31,328) $244,592
========= ======= ========= ========= =========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ----------------------------------------------------------
Production $360,422 $360,463
Transmission 271,304 268,695
Distribution 460,123 456,278
General 119,342 117,792
Construction Work in Progress 28,834 30,199
--------- -----------
TOTAL 1,240,025 1,233,427
Accumulated Depreciation and Amortization 466,792 460,513
--------- -----------
TOTAL - NET 773,233 772,914
--------- -----------
OTHER PROPERTY AND INVESTMENTS
- ----------------------------------------------------------
Non-Utility Property, Net 1,282 1,286
--------- -----------
TOTAL 1,282 1,286
--------- -----------
CURRENT ASSETS
- ----------------------------------------------------------
Cash and Cash Equivalents 2,835 2,863
Advances to Affiliates 19,990 41,593
Accounts Receivable:
Customers 62,711 56,670
Affiliated Companies 19,980 28,910
Accrued Unbilled Revenues 4,119 4,871
Miscellaneous 416 3,411
Allowance for Uncollectible Accounts (293) (175)
Fuel Inventory 8,582 10,925
Materials and Supplies 8,773 8,866
Risk Management Assets 4,739 10,340
Margin Deposits 2,328 1,285
Prepayments and Other 1,883 1,834
--------- -----------
TOTAL 136,063 171,393
--------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ----------------------------------------------------------
Regulatory Assets:
Deferred Fuel Costs 26,680 26,680
Deferred Debt - Restructuring 6,458 6,579
Unamortized Loss on Reacquired Debt 3,444 3,929
Other 3,140 3,332
Long-term Risk Management Assets 1,296 3,106
Deferred Charges 35,339 20,290
--------- -----------
TOTAL 76,357 63,916
--------- -----------
TOTAL ASSETS $986,935 $1,009,509
========= ===========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 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 136,355 125,428
Accumulated Other Comprehensive Income (Loss) (31,328) (26,718)
--------- -----------
Total Common Shareholder's Equity 244,592 238,275
Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,357 2,357
--------- -----------
Total Shareholder's Equity 246,949 240,632
Long-term Debt 314,279 314,249
--------- -----------
TOTAL 561,228 554,881
--------- -----------
CURRENT LIABILITIES
- -------------------------------------------------------------------
Long-term Debt Due Within One Year 18,469 42,505
Accounts Payable:
General 19,923 28,190
Affiliated Companies 37,641 40,601
Customer Deposits 466 161
Taxes Accrued 31,412 22,877
Interest Accrued 4,076 6,038
Risk Management Liabilities 10,920 8,658
Obligations Under Capital Leases 202 203
Other 7,112 9,419
--------- -----------
TOTAL 130,221 158,652
--------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- -------------------------------------------------------------------
Deferred Income Taxes 110,842 113,019
Long-term Risk Management Liabilities 689 1,094
Regulatory Liabilities:
Asset Removal Costs 78,078 76,740
Deferred Investment Tax Credits 19,651 19,990
Retail Clawback 11,804 11,804
Excess Earnings 14,141 14,262
SFAS 109 Regulatory Liability, Net 13,349 13,655
Other 1,724 1,826
Obligations Under Capital Leases 247 270
Deferred Credits and Other 44,961 43,316
--------- -----------
TOTAL 295,486 295,976
--------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $986,935 $1,009,509
========= ===========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ----------------------------------------------------------
Net Income $12,953 $9,836
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (3,071)
Depreciation and Amortization 9,692 9,532
Deferred Income Taxes (1) (5,666)
Deferred Investment Tax Credits (339) (380)
Deferred Property Taxes (11,100) (10,868)
Mark-to-Market of Risk Management Contracts 2,096 608
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 6,754 36,645
Fuel, Materials and Supplies 2,436 3,306
Accounts Payable (11,227) (54,482)
Taxes Accrued 8,535 21,728
Change in Other Assets (6,128) (2,767)
Change in Other Liabilities (1,118) 5,646
-------- ---------
Net Cash Flows From Operating Activities 12,553 10,067
-------- ---------
INVESTING ACTIVITIES
- ----------------------------------------------------------
Construction Expenditures (8,122) (10,197)
-------- ---------
Net Cash Flows Used For Investing Activities (8,122) (10,197)
-------- ---------
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 21,603 (88,867)
Dividends Paid on Common Stock (2,000) (4,970)
Dividends Paid on Cumulative Preferred Stock (26) (26)
-------- ---------
Net Cash Flows From (Used For) Financing Activities (4,459) 3,592
-------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (28) 3,462
Cash and Cash Equivalents at Beginning of Period 2,863 1,219
-------- ---------
Cash and Cash Equivalents at End of Period $2,835 $4,681
======== =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $7,568,000 and $2,021,000 and for income taxes was ($412,000) and
($8,873,000) in 2004 and 2003, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
The notes to TNC's financial statements are combined with the notes to
respective 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 first quarter of 2004 decreased $92 million from the prior
year period primarily due to the Cumulative Effect of Accounting Changes of $77
million recorded in 2003 and an increase in Depreciation and Amortization
expense of $12 million over the first quarter of 2003.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income for 2004 decreased by $26 million from 2003 primarily due to
the following:
o An $11 million decrease in revenues from risk management activities included
in Operating Income.
o A decrease of $3 million in Sales to AEP Affiliates due to decreased power
available for sale caused by planned plant outages in the first quarter of
2004.
o An increase in Depreciation and Amortization expense of $12 million
primarily due to reduced expense in 2003 attributable to the adoption of
SFAS 143 for regulated operations and to a lesser degree, due to a greater
depreciable base in 2004 which included the addition of capitalized software
costs.
o An increase in Maintenance expense of $9 million primarily due to planned
maintenance at Amos and Kanawha River Plants relating to scheduled outages
in 2004.
o An increase in Other Operation expense of $7 million primarily due to higher
employee-related expenses in the first quarter of 2004.
o A $9 million increase in purchased power essentially offset by decreased
fuel expenses as purchased power was used to offset decreased generation
resulting from the planned plant outages in 2004.
The decrease in Operating Income for 2004 was partially offset by:
o An increase in off-system sales and transmission revenues totaling $4
million.
o A decrease in Income Taxes of $9 million due to the decrease in pre-tax
book operating income in 2004.
Other Impacts on Earnings
- -------------------------
Nonoperating income increased $10 million in the first quarter of 2004 compared
to 2003 primarily due to reduced losses from risk management activities
resulting from AEP's plan to exit risk management activities in areas outside of
its traditional market area. The increase in nonoperating income was partially
offset by a $3 million increase in nonoperating income taxes resulting from an
increase in pre-tax nonoperating book income. Interest charges decreased $4
million in the first quarter of 2004 from the prior year period due to lower
debt levels and reduced interest rates and increased Allowance for Funds Used
During Construction in 2004.
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 three months ended March 31, 2004 and 2003 were as follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $45,881 $4,285
--------- ---------
Cash flow from (used for):
Operating activities 182,058 220,018
Investing activities (91,039) (54,363)
Financing activities (131,630) (159,491)
--------- ---------
Net increase (decrease) in cash and cash equivalents (40,611) 6,164
--------- ---------
Cash and cash equivalents at end of period $5,270 $10,449
========= =========
Operating Activities
- --------------------
Cash Flows From Operating Activities in the first quarter of 2004 were $182
million primarily due to Net Income and changes in Accounts Receivable and
accrued expenses.
Investing Activities
- --------------------
Construction expenditures in 2004 versus 2003 increased $34 million. The current
year expenditures of $91 million were focused primarily on projects to improve
service reliability for transmission and distribution, as well as environmental
upgrades.
Financing Activities
- --------------------
In 2004, we retired $40 million of Installment Purchase Contracts, paid $25
million in dividends and repaid $66 million of Advances from Affiliates.
Financing Activity
- ------------------
Long-term debt issuances and retirements during the first quarter of 2004 were:
Issuances
---------
None.
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase
Contracts $40,000 5.45 2019
Significant Factors
- -------------------
See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.
Critical Accounting Policies
- ----------------------------
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
Three Months Ended March 31, 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) (11,026)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 1,050
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) 9,916
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) 4,899
--------
Total MTM Risk Management Contract Net Assets 72,905
Net Cash Flow Hedge Contracts (f) (4,272)
DETM Assignment (g) (29,111)
--------
Total MTM Risk Management Contract Net Assets at March 31, 2004 $39,522
========
(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
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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(5,053) $2,303 $(92) $804 $- $- $(2,038)
Prices Provided by Other External Sources -
OTC Broker Quotes (a) 23,710 14,113 6,191 2,187 1,145 - 47,346
Prices Based on Models and Other Valuation
Methods (b) (123) 260 4,234 5,696 5,596 11,934 27,597
-------- -------- -------- ------- ------- -------- --------
Total $18,534 $16,676 $10,333 $8,687 $6,741 $11,934 $72,905
======== ======== ======== ======= ======= ======== ========
(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
- --------------------------------------------------------------------------
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, the table does not provide a full
picture of our hedging activity. In accordance with GAAP, all amounts are
presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 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) (2,887) - - (2,887)
Reclassifications from AOCI to Net
Income (b) (249) 2 84 (163)
-------- ------ -------- --------
Ending Balance March 31, 2004 $(2,777) $(181) $(1,661) $(4,619)
======== ====== ======== ========
(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 $1,630 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:
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
------------------------- -------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$672 $2,123 $1,162 $590 $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 $86 million and $102 million at March 31, 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 Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------------------
Electric Generation, Transmission and Distribution $472,575 $479,333
Sales to AEP Affiliates 53,882 56,895
--------- ---------
TOTAL 526,457 536,228
--------- ---------
OPERATING EXPENSES
- --------------------------------------------------------------
Fuel for Electric Generation 110,711 119,865
Purchased Electricity for Resale 16,644 17,118
Purchased Electricity from AEP Affiliates 90,487 80,720
Other Operation 68,907 62,115
Maintenance 41,320 32,738
Depreciation and Amortization 47,913 36,008
Taxes Other Than Income Taxes 23,453 25,079
Income Taxes 40,440 49,901
--------- ---------
TOTAL 439,875 423,544
--------- ---------
OPERATING INCOME 86,582 112,684
Nonoperating Income (Loss) 5,547 (4,300)
Nonoperating Expenses 2,533 3,858
Nonoperating Income Tax Credit (362) (3,733)
Interest Charges 25,437 29,106
--------- ---------
Income Before Cumulative Effect of Accounting Changes 64,521 79,153
Cumulative Effect of Accounting Changes (Net of Tax) - 77,257
--------- ---------
NET INCOME 64,521 156,410
Preferred Stock Dividend Requirements (Including Capital Stock Expense) 823 984
--------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $63,698 $155,426
========= =========
The common stock of APCo is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 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 (32,066) (32,066)
Preferred Stock Dividends (361) (361)
Capital Stock Expense 623 (623) -
SFAS 71 Reapplication 162 162
-----------
TOTAL 1,133,792
-----------
COMPREHENSIVE INCOME
- --------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (12,518) (12,518)
NET INCOME 156,410 156,410
-----------
TOTAL COMPREHENSIVE INCOME 143,892
--------- --------- --------- --------- -----------
MARCH 31, 2003 $260,458 $718,027 $383,799 $(84,600) $1,277,684
========= ========= ========= ========= ===========
DECEMBER 31, 2003 $260,458 $719,899 $408,718 $(52,088) $1,336,987
Common Stock Dividends (25,000) (25,000)
Preferred Stock Dividends (200) (200)
Capital Stock Expense 623 (623) -
-----------
TOTAL 1,311,787
-----------
COMPREHENSIVE INCOME
- --------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (3,050) (3,050)
NET INCOME 64,521 64,521
-----------
TOTAL COMPREHENSIVE INCOME 61,471
--------- --------- --------- --------- -----------
MARCH 31, 2004 $260,458 $720,522 $447,416 $(55,138) $1,373,258
========= ========= ========= ========= ===========
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ----------------------------------------------------------
Production $2,298,815 $2,287,043
Transmission 1,245,757 1,240,889
Distribution 2,018,675 2,006,329
General 301,462 294,786
Construction Work in Progress 353,053 311,884
----------- -----------
TOTAL 6,217,762 6,140,931
Accumulated Depreciation and Amortization 2,350,438 2,321,360
----------- -----------
TOTAL - NET 3,867,324 3,819,571
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ----------------------------------------------------------
Non-Utility Property, Net 20,503 20,574
Other Investments 24,586 26,668
----------- -----------
TOTAL 45,089 47,242
----------- -----------
CURRENT ASSETS
- ----------------------------------------------------------
Cash and Cash Equivalents 5,270 45,881
Accounts Receivable:
Customers 116,260 133,717
Affiliated Companies 114,535 137,281
Accrued Unbilled Revenues 22,467 35,020
Miscellaneous 4,668 3,961
Allowance for Uncollectible Accounts (5,227) (2,085)
Fuel Inventory 50,775 42,806
Materials and Supplies 89,137 71,978
Risk Management Assets 95,607 71,189
Margin Deposits 6,865 11,525
Prepayments and Other 13,543 13,301
----------- -----------
TOTAL 513,900 564,574
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ----------------------------------------------------------
Regulatory Assets:
Transition Regulatory Assets 28,651 30,855
SFAS 109 Regulatory Asset, Net 326,533 325,889
Unamortized Loss on Reacquired Debt 18,852 19,005
Other Regulatory Assets 44,186 41,447
Long-term Risk Management Assets 94,899 70,900
Deferred Property Taxes 38,440 35,343
Other Deferred Charges 22,080 22,185
----------- -----------
TOTAL 573,641 545,624
----------- -----------
TOTAL ASSETS $4,999,954 $4,977,011
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 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 720,522 719,899
Retained Earnings 447,416 408,718
Accumulated Other Comprehensive Income (Loss) (55,138) (52,088)
----------- -----------
Total Common Shareholder's Equity 1,373,258 1,336,987
Cumulative Preferred Stock Not Subject to Mandatory Redemption 17,784 17,784
----------- -----------
Total Shareholder's Equity 1,391,042 1,354,771
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption 5,360 5,360
Long-term Debt 1,658,715 1,703,073
----------- -----------
TOTAL 3,055,117 3,063,204
----------- -----------
CURRENT LIABILITIES
- ------------------------------------------------------------------------
Long-term Debt Due Within One Year 166,009 161,008
Advances from Affiliates 16,566 82,994
Accounts Payable:
General 133,897 140,497
Affiliated Companies 62,635 81,812
Customer Deposits 44,914 33,930
Taxes Accrued 77,169 50,259
Interest Accrued 39,982 22,113
Risk Management Liabilities 81,440 51,430
Obligations Under Capital Leases 8,384 9,218
Other 54,309 60,289
----------- -----------
TOTAL 685,305 693,550
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ------------------------------------------------------------------------
Deferred Income Taxes 817,099 803,355
Regulatory Liabilities:
Asset Removal Costs 94,638 92,497
Deferred Investment Tax Credits 29,456 30,545
Over Recovery of Fuel Cost 71,203 68,704
Other Regulatory Liabilities 24,762 17,326
Long-term Risk Management Liabilities 69,544 54,327
Obligations Under Capital Leases 14,999 16,134
Asset Retirement Obligation 22,201 21,776
Deferred Credits and Other 115,630 115,593
----------- -----------
TOTAL 1,259,532 1,220,257
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $4,999,954 $4,977,011
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ---------------------------------------------------------
Net Income $64,521 $156,410
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (77,257)
Depreciation and Amortization 47,913 36,008
Deferred Income Taxes 14,742 1,005
Deferred Investment Tax Credits (1,089) 245
Deferred Power Supply Costs, Net 2,499 63,837
Mark to Market of Risk Management Contracts (8,015) 5,383
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 55,191 13,830
Fuel, Materials and Supplies (25,128) 12,018
Accounts Payable (25,777) (14,074)
Taxes Accrued 26,910 59,261
Interest Accrued 17,869 16,785
Incentive Plan Accrued (3,172) (9,595)
Rate Stabilization Deferral - (75,601)
Change in Operating Reserves (69) 20,095
Change in Other Assets (2,073) (14,446)
Change in Other Liabilities 17,736 26,114
--------- ---------
Net Cash Flows From Operating Activities 182,058 220,018
--------- ---------
INVESTING ACTIVITIES
- ---------------------------------------------------------
Construction Expenditures (91,067) (56,627)
Proceeds from Sale of Property and Other 28 2,264
--------- ---------
Net Cash Flows Used For Investing Activities (91,039) (54,363)
--------- ---------
FINANCING ACTIVITIES
- ---------------------------------------------------------
Retirement of Long-term Debt (40,002) -
Change in Advances from Affiliates, Net (66,428) (127,064)
Dividends Paid on Common Stock (25,000) (32,066)
Dividends Paid on Cumulative Preferred Stock (200) (361)
--------- ---------
Net Cash Flows Used For Financing Activities (131,630) (159,491)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (40,611) 6,164
Cash and Cash Equivalents at Beginning of Period 45,881 4,285
--------- ---------
Cash and Cash Equivalents at End of Period $5,270 $10,449
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $5,214,000 and $11,191,000 and for income taxes was $1,599,000
and $(11,498,000) in 2004 and 2003, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
The notes to APCo's consolidated financial statements are combined with the
notes to respective 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
- ---------------------
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
The decrease in Net Income of $21 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 $3 million increase in Depreciation and Amortization
expense and a $6 million increase in Nonoperating Income Taxes, which was offset
by a $3 million increase in total operating revenues and a $12 million increase
in nonoperating income associated with risk management activities.
Operating Income
- ----------------
Operating Income decreased $1 million primarily due to:
o A decrease of $3 million in wholesale sales to municipal customers as the
result of the expiration of the final municipal contract at the end of 2003.
o A decrease of $1 million in sales for resale to affiliated companies due to
lower price realizations during 2004.
o A decrease of $2 million in operating revenues relating to risk management
activities as a result of lower volumes.
o An increase of $2 million in Maintenance expense due primarily to boiler
overhaul work from scheduled and forced outages.
o An increase of $3 million in Depreciation and Amortization expense as a
result of a greater depreciable base in 2004, including capital software
costs and the increased amortization of regulatory assets due to a
federal tax adjustment, which increased the regulatory asset amount, and a
corresponding quarterly adjustment to the amortization amount.
The decrease in Operating Income was partially offset by:
o An increase of $9 million in retail electric revenues primarily due to
growth in the residential and commercial customer base and increased KWH
usage per customer in the first quarter of 2004.
o A decrease of $1 million in Income Taxes due to a decrease in pre-tax
operating book income.
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $12 million primarily due to favorable results
from risk management activities in the first quarter of 2004 compared to losses
that were recorded in the first quarter of 2003.
Nonoperating Income Tax increased $6 million due to an increase in pre-tax
nonoperating book income.
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
- ------------------
There were no long-term debt issuances or retirements in the first three months
of 2004.
Significant Factors
- -------------------
See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.
Critical Accounting Policies
- ----------------------------
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
Three Months Ended March 31, 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) (6,212)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 646
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) 12,040
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) -
--------
Total MTM Risk Management Contract Net Assets 44,811
Net Cash Flow Hedge Contracts (f) (2,626)
DETM Assignment (g) (17,893)
--------
Total MTM Risk Management Contract Net Assets at March 31, 2004 $24,292
========
(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
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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(3,106) $1,416 $(57) $494 $- $- $(1,253)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 14,573 8,675 3,805 1,343 704 - 29,100
Prices Based on Models and Other
Valuation Methods (b) (75) 160 2,603 3,501 3,440 7,335 16,964
-------- -------- ------- -------- -------- ------- --------
Total $11,392 $10,251 $6,351 $5,338 $4,144 $7,335 $44,811
======== ======== ======= ======== ======== ======= ========
(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
- --------------------------------------------------------------------------
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, the table does not provide a full
picture of our hedging activity. In accordance with GAAP, all amounts are
presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $202
Changes in Fair Value (a) (1,745)
Reclassifications from AOCI to Net Income (b) (165)
----------
Ending Balance March 31, 2004 $(1,708)
========
(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 $790 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:
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
------------------------- -------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$413 $1,305 $714 $363 $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 $86 million and $98 million at March 31, 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 Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES
- ------------------------------------------------------
Electric Generation, Transmission and Distribution $343,686 $338,437
Sales to AEP Affiliates 18,619 20,768
--------- ---------
TOTAL 362,305 359,205
--------- ---------
OPERATING EXPENSES
- ------------------------------------------------------
Fuel for Electric Generation 41,851 47,540
Fuel From Affiliates for Electric Generation 8,848 4,503
Purchased Electricity for Resale 4,681 4,198
Purchased Electricity from AEP Affiliates 81,715 82,149
Other Operation 57,681 56,385
Maintenance 16,826 14,559
Depreciation and Amortization 36,818 33,737
Taxes Other Than Income Taxes 35,326 35,608
Income Taxes 24,465 25,375
--------- ---------
TOTAL 308,211 304,054
--------- ---------
OPERATING INCOME 54,094 55,151
Nonoperating Income (Loss) 5,078 (6,676)
Nonoperating Expenses 734 2,201
Nonoperating Income Tax Expense (Credit) 919 (5,547)
Interest Charges 12,814 13,462
--------- ---------
Income Before Extraordinary Item and Cumulative Effect
of Accounting Changes 44,705 38,359
Cumulative Effect of Accounting Changes (Net of Tax) - 27,283
--------- ---------
NET INCOME 44,705 65,642
Preferred Stock - Capital Stock Expense 254 254
--------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $44,451 $65,388
========= =========
The common stock of CSPCo is wholly-owned by AEP.
See Notes to Respective Financial Statements 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 Three Months Ended March 31, 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 (38,311) (38,311)
Capital Stock Expense 254 (254) -
---------
TOTAL 809,353
---------
COMPREHENSIVE INCOME
- -----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (7,343) (7,343)
NET INCOME 65,642 65,642
---------
TOTAL COMPREHENSIVE INCOME 58,299
-------- --------- --------- --------- ---------
MARCH 31, 2003 $41,026 $575,638 $317,688 $(66,700) $867,652
======== ========= ========= ========= =========
DECEMBER 31, 2003 $41,026 $576,400 $326,782 $(46,327) $897,881
Common Stock Dividends Declared (31,250) (31,250)
Capital Stock Expense 254 (254) -
---------
TOTAL 866,631
---------
COMPREHENSIVE INCOME
- -----------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,910) (1,910)
NET INCOME 44,705 44,705
---------
TOTAL COMPREHENSIVE INCOME 42,795
-------- --------- --------- --------- ---------
MARCH 31, 2004 $41,026 $576,654 $339,983 $(48,237) $909,426
======== ========= ========= ========= =========
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -------------------------------------------------------
Production $1,614,315 $1,610,888
Transmission 427,609 425,512
Distribution 1,265,858 1,253,760
General 168,434 166,002
Construction Work in Progress 115,099 114,281
----------- -----------
TOTAL 3,591,315 3,570,443
Accumulated Depreciation and Amortization 1,410,524 1,389,586
----------- -----------
TOTAL - NET 2,180,791 2,180,857
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- -------------------------------------------------------
Non-Utility Property, Net 22,006 22,417
Other Investments 7,838 8,663
----------- -----------
TOTAL 29,844 31,080
----------- -----------
CURRENT ASSETS
- -------------------------------------------------------
Cash and Cash Equivalents 4,144 4,142
Advances to Affiliates, Net 18,058 -
Accounts Receivable:
Customers 36,934 47,099
Affiliated Companies 53,689 68,168
Accrued Unbilled Revenues 24,487 23,723
Miscellaneous 5,665 5,257
Allowance for Uncollectible Accounts (150) (531)
Fuel 18,139 14,365
Materials and Supplies 56,112 44,377
Risk Management Assets 58,764 40,095
Margin Deposits 3,956 6,636
Prepayments and Other 12,691 12,444
----------- -----------
TOTAL 292,489 265,775
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- -------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Assets, Net 16,215 16,027
Transition Regulatory Assets 180,281 188,532
Unamortized Loss on Reacquired Debt 13,418 13,659
Other 21,692 24,966
Long-term Risk Management Assets 58,329 39,932
Deferred Property Taxes 47,251 62,262
Deferred Charges 19,339 15,276
----------- -----------
TOTAL 356,525 360,654
----------- -----------
TOTAL ASSETS $2,859,649 $2,838,366
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 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 576,654 576,400
Retained Earnings 339,983 326,782
Accumulated Other Comprehensive Income (Loss) (48,237) (46,327)
----------- -----------
Total Common Shareholder's Equity 909,426 897,881
----------- -----------
Long-term Debt 842,948 886,564
----------- -----------
TOTAL 1,752,374 1,784,445
----------- -----------
CURRENT LIABILITIES
- ---------------------------------------------------------
Long-term Debt Due Within One Year 54,695 11,000
Advances from Affiliates, Net - 6,517
Accounts Payable:
General 51,621 58,220
Affiliated Companies 49,503 53,572
Customer Deposits 25,775 19,727
Taxes Accrued 125,135 132,853
Interest Accrued 9,945 16,528
Risk Management Liabilities 50,056 28,966
Obligations Under Capital Leases 4,057 4,221
Other 24,472 25,364
----------- -----------
TOTAL 395,259 356,968
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ---------------------------------------------------------
Deferred Income Taxes 465,384 458,498
Regulatory Liabilities:
Asset Removal Costs 100,382 99,119
Deferred Investment Tax Credits 30,045 30,797
Long-term Risk Management Liabilities 42,745 30,598
Obligations Under Capital Leases 10,497 11,397
Asset Retirement Obligations 8,911 8,740
Deferred Credits and Other 54,052 57,804
----------- -----------
TOTAL 712,016 696,953
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $2,859,649 $2,838,366
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- -------------------------------------------------------
Net Income $44,705 $65,642
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (27,283)
Depreciation and Amortization 36,818 33,737
Deferred Income Taxes 7,726 (3,095)
Deferred Investment Tax Credits (752) (763)
Mark-to-Market of Risk Management Contracts (6,766) 10,958
Gain on Sale of Assets (1,786) -
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 23,091 16,673
Fuel, Materials and Supplies (15,509) 8,498
Accounts Payable (10,668) (39,247)
Taxes Accrued (7,718) 11,817
Interest Accrued (6,583) 3,894
Change in Other Assets 16,473 (2,240)
Change in Other Liabilities 2,041 9,141
-------- ---------
Net Cash Flows From Operating Activities 81,072 87,732
-------- ---------
INVESTING ACTIVITIES
- -------------------------------------------------------
Construction Expenditures (27,360) (27,269)
Proceeds from Sale of Property and Other 2,115 190
-------- ---------
Net Cash Flows Used For Investing Activities (25,245) (27,079)
-------- ---------
FINANCING ACTIVITIES
- -------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated - 494,350
Change in Advances to/from Affiliates, Net (24,575) (56,203)
Retirement of Long-term Debt - Nonaffiliated - (44,000)
Retirement of Long-term Debt - Affiliated - (160,000)
Change in Short-term Debt - Affiliates - (250,000)
Dividends Paid on Common Stock (31,250) (38,311)
-------- ---------
Net Cash Flows Used For Financing Activities (55,825) (54,164)
-------- ---------
Net Increase in Cash and Cash Equivalents 2 6,489
Cash and Cash Equivalents at Beginning of Period 4,142 1,479
-------- ---------
Cash and Cash Equivalents at End of Period $4,144 $7,968
======== =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $18,971,000 and $9,219,000 and for income taxes was $(3,806,000)
and $(16,019,000) in 2004 and 2003, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
The notes to CSPCo's consolidated financial statements are combined with the
notes to respective 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
- ---------------------
During 2004, Net Income increased $15 million including an unfavorable $3
million Cumulative Effect of Accounting Change in 2003. During 2004, Net Income
Before Cumulative Effect of Accounting Change increased $12 million due to
reduced financing costs and an improvement in margins on nonoperating risk
management activities.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $3 million primarily due to:
o Decreased Sales to AEP Affiliates of $11 million due to declines in the
price and volume of sales to the AEP Power Pool reflecting lower demand for
electricity and lower capacity revenues.
o Increased Maintenance expense of $7 million due primarily to the cost of a
planned maintenance outage at one unit of Rockport Plant and increased cost
of overhead lines and their right-of-way maintenance.
o Increased Income Tax expense of $3 million reflecting an increase in pre-tax
operating income.
The decrease in Operating Income was partially offset by:
o Increased retail revenues of $7 million due primarily to an improvement in
industrial sales reflecting the recovery of the economy and the end of
amortization for Cook outage settlements.
o Decreased Fuel for Electric Generation expense of $9 million reflecting
a change in fuel mix as nuclear generation increased 21% and coal-fired
generation declined 22% due to generating unit availability.
o Decreased Taxes Other Than Income Taxes of $2 million primarily due to
decreased Federal Insurance Contributions Act taxes reflecting a reduction
in employees from the sustained earnings improvement initiative and timing
of payroll accrual.
Other Impacts on Earnings
- -------------------------
Nonoperating Income increased $14 million primarily due to improved risk
management activities.
Nonoperating Income Taxes increased $6 million reflecting the increase in
pre-tax nonoperating income.
Interest Charges decreased $6 million primarily due to a reduction in
outstanding long-term debt of $255 million which was retired in May 2003 using
lower rate short-term debt, maturity of $30 million first mortgage bonds in
November 2003 and the refinancing of $65 million installment purchase contracts
at lower interest rates.
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 three months of 2004 and 2003 were as follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $3,914 $3,237
--------- --------
Cash flow from (used for):
Operating activities 182,883 80,169
Investing activities (36,340) (28,222)
Financing activities (147,177) (48,664)
--------- --------
Net increase (decrease) in cash and cash equivalents (634) 3,283
--------- --------
Cash and cash equivalents at end of period $3,280 $6,520
========= ========
Operating Activities
- --------------------
Operating activities during 2004 provided $103 million more cash than during
2003 largely due to increased net income of $15 million and improved working
capital requirements.
Investing Activities
- --------------------
Cash flows Used For Investing Activities during 2004 were $8 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 $99 million more cash from operations than
during 2003 primarily to reduce short-term debt outstanding and pay common
dividends.
Financing Activity
- ------------------
There were no long-term debt issuances or retirements during the first three
months of 2004.
Off-Balance Sheet Arrangements
- ------------------------------
We enter into off-balance sheet arrangements for various reasons including
accelerating cash collections, reducing operational expenses and spreading risk
of loss to third parties. Our 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 plans limit 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.
Significant Factors
- -------------------
See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.
Critical Accounting Policies
- ----------------------------
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
Three Months Ended March 31, 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) (6,529)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 708
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) 4,832
Changes in Fair Value Risk Management Contracts Allocated to Regulated
Jurisdictions (e) 8,064
--------
Total MTM Risk Management Contract Net Assets 49,070
Net Cash Flow Hedge Contracts (f) (2,878)
DETM Assignment (g) (19,612)
--------
Total MTM Risk Management Contract Net Assets at March 31, 2004 $26,580
========
(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
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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- --------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(3,404) $1,552 $(62) $542 $- $- $(1,372)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 15,992 9,508 4,170 1,473 771 - 31,914
Prices Based on Models and Other Valuation
Methods (b) (147) 175 2,853 3,837 3,770 8,040 18,528
-------- -------- -------- ------- ------- ------- --------
Total $12,441 $11,235 $6,961 $5,852 $4,541 $8,040 $49,070
======== ======== ======= ======= ======= ======= ========
(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, the table does not provide a full
picture of our hedging activity. In accordance with GAAP, all amounts are
presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2004
Power
-----
(in thousands)
Beginning Balance December 31, 2003 $222
Changes in Fair Value (a) (1,912)
Reclassifications from AOCI to Net Income (b) (181)
--------
Ending Balance March 31, 2004 $(1,871)
========
(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 $865 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:
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
------------------------------------------ ---------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$453 $1,430 $783 $398 $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 $61 million and $79 million at March 31, 2004 and December 31, 2003,
respectively. We would not expect to liquidate our entire debt portfolio in a
one-year holding period, therefore a near term change in interest rates should
not negatively affect our results of operation or consolidated financial
position.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $353,398 $349,787
Sales to AEP Affiliates 57,645 68,811
--------- ---------
TOTAL 411,043 418,598
--------- ---------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 64,041 73,094
Purchased Electricity for Resale 6,363 6,282
Purchased Electricity from AEP Affiliates 63,128 65,898
Other Operation 101,058 101,381
Maintenance 38,042 31,367
Depreciation and Amortization 42,715 43,726
Taxes Other Than Income Taxes 15,216 16,821
Income Taxes 24,299 21,039
--------- ---------
TOTAL 354,862 359,608
--------- ---------
OPERATING INCOME 56,181 58,990
Nonoperating Income 20,588 6,274
Nonoperating Expenses 14,851 15,590
Nonoperating Income Tax Expense (Credit) 1,613 (4,451)
Interest Charges 17,929 23,438
--------- ---------
Net Income Before Cumulative Effect of Accounting Change 42,376 30,687
Cumulative Effect of Accounting Change (Net of Tax) - (3,160)
--------- ---------
NET INCOME 42,376 27,527
Preferred Stock Dividend Requirements (Including Capital Stock Expense) 118 1,149
--------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $42,258 $26,378
========= =========
The common stock of I&M is wholly-owned by AEP.
See Notes to Respective Financial Statements 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 Three Months Ended March 31, 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 (10,000) (10,000)
Preferred Stock Dividends (1,115) (1,115)
Capital Stock Expense 34 (34) -
-----------
1,007,538
COMPREHENSIVE INCOME
- -------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (7,857) (7,857)
NET INCOME 27,527 27,527
-----------
TOTAL COMPREHENSIVE INCOME 19,670
-------- --------- --------- --------- -----------
MARCH 31, 2003 $56,584 $858,594 $160,374 $(48,344) $1,027,208
======== ========= ========= ========= ===========
DECEMBER 31, 2003 $56,584 $858,694 $187,875 $(25,106) $1,078,047
Common Stock Dividends (29,646) (29,646)
Preferred Stock Dividends (84) (84)
Capital Stock Expense 34 (34) -
-----------
1,048,317
COMPREHENSIVE INCOME
- -------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (2,093) (2,093)
NET INCOME 42,376 42,376
-----------
TOTAL COMPREHENSIVE INCOME 40,283
-------- --------- --------- --------- -----------
MARCH 31, 2004 $56,584 $858,728 $200,487 $(27,199) $1,088,600
======== ========= ========= ========= ===========
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- --------------------------------------------------
Production $2,889,689 $2,878,051
Transmission 1,002,532 1,000,926
Distribution 964,987 958,966
General (including nuclear fuel) 270,024 274,283
Construction Work in Progress 191,518 193,956
----------- -----------
TOTAL 5,318,750 5,306,182
Accumulated Depreciation and Amortization 2,516,959 2,490,912
----------- -----------
TOTAL - NET 2,801,791 2,815,270
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- --------------------------------------------------
Nuclear Decommissioning and Spent Nuclear Fuel
Disposal Trust Funds 1,035,851 982,394
Non-Utility Property, Net 50,858 52,303
Other Investments 41,823 43,797
----------- -----------
TOTAL 1,128,532 1,078,494
----------- -----------
CURRENT ASSETS
- --------------------------------------------------
Cash and Cash Equivalents 3,280 3,914
Advances to Affiliates 16,625 -
Accounts Receivable:
Customers 49,917 63,084
Affiliated Companies 84,378 124,826
Miscellaneous 5,020 4,498
Allowance for Uncollectible Accounts (63) (531)
Fuel 34,145 33,968
Materials and Supplies 119,117 105,328
Risk Management Assets 64,429 44,071
Margin Deposits 4,323 7,245
Prepayments and Other 11,885 10,673
----------- -----------
TOTAL 393,056 397,076
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- --------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 148,374 151,973
Incremental Nuclear Refueling Outage Expenses, Net 44,147 57,326
Other 73,873 66,978
Long-term Risk Management Assets 63,933 43,768
Deferred Property Taxes 29,875 21,916
Deferred Charges and Other Assets 25,976 26,270
----------- -----------
TOTAL 386,178 368,231
----------- -----------
TOTAL ASSETS $4,709,557 $4,659,071
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 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 858,728 858,694
Retained Earnings 200,487 187,875
Accumulated Other Comprehensive Income (Loss) (27,199) (25,106)
----------- -----------
Total Common Shareholder's Equity 1,088,600 1,078,047
Cumulative Preferred Stock - Not Subject to Mandatory Redemption 8,101 8,101
----------- -----------
Total Shareholder's Equity 1,096,701 1,086,148
Liability for Cumulative Preferred Stock - Subject to Mandatory
Redemption 61,445 63,445
Long-term Debt 1,135,101 1,134,359
----------- -----------
TOTAL 2,293,247 2,283,952
----------- -----------
CURRENT LIABILITIES
- --------------------------------------------------------------------
Long-term Debt Due Within One Year 205,000 205,000
Advances from Affiliates - 98,822
Accounts Payable:
General 77,610 101,776
Affiliated Companies 42,432 47,484
Customer Deposits 30,827 21,955
Taxes Accrued 79,943 42,189
Interest Accrued 22,970 17,963
Risk Management Liabilities 54,931 31,898
Obligations Under Capital Leases 6,212 6,528
Other 76,141 57,675
----------- -----------
TOTAL 596,066 631,290
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- --------------------------------------------------------------------
Deferred Income Taxes 334,149 337,376
Regulatory Liabilities:
Asset Removal Costs 266,306 263,015
Deferred Investment Tax Credits 88,446 90,278
Excess ARO for Nuclear Decommissioning 251,539 215,715
Other 82,673 61,268
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 69,252 70,179
Long-term Risk Management Liabilities 46,851 33,537
Obligations Under Capital Leases 30,219 31,315
Asset Retirement Obligations 562,918 553,219
Deferred Credits and Other 87,891 87,927
----------- -----------
TOTAL 1,820,244 1,743,829
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $4,709,557 $4,659,071
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ----------------------------------------------------------------
Net Income $42,376 $27,527
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change - 3,160
Depreciation and Amortization 42,715 43,726
Deferred Income Taxes 1,895 (12,367)
Deferred Investment Tax Credits (1,832) (1,835)
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses, Net 13,179 9,410
Unrecovered Fuel and Purchased Power Costs (120) 9,375
Amortization of Nuclear Outage Costs - 10,000
Mark-to-Market of Risk Management Contracts (7,396) 10,543
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 52,625 (6,726)
Fuel, Materials and Supplies (13,966) 822
Accounts Payable (29,218) (49,480)
Taxes Accrued 37,754 19,166
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets (6,446) 3,649
Change in Other Liabilities 32,853 (5,265)
--------- --------
Net Cash Flows From Operating Activities 182,883 80,169
--------- --------
INVESTING ACTIVITIES
- ----------------------------------------------------------------
Construction Expenditures (36,353) (28,234)
Other 13 12
--------- --------
Net Cash Flows Used For Investing Activities (36,340) (28,222)
--------- --------
FINANCING ACTIVITIES
- ----------------------------------------------------------------
Retirement of Cumulative Preferred Stock (2,000) -
Change in Advances to/from Affiliates, Net (115,447) (37,549)
Dividends Paid on Common Stock (29,646) (10,000)
Dividends Paid on Cumulative Preferred Stock (84) (1,115)
--------- --------
Net Cash Flows Used For Financing Activities (147,177) (48,664)
--------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (634) 3,283
Cash and Cash Equivalents at Beginning of Period 3,914 3,237
--------- --------
Cash and Cash Equivalents at End of Period $3,280 $6,520
========= ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $12,007,000 and $18,211,000 and for income taxes was
($5,480,000) and $20,011,000 in 2004 and 2003, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
The notes to I&M's consolidated financial statements are combined with the notes
to respective 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
- ---------------------
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Net Income for the first quarter of 2004 increased $2 million over the first
quarter of 2003 primarily due to reduced losses on risk management activities,
partially offset by the Cumulative Effect of Accounting Change recorded in 2003.
Operating Income
- ----------------
Operating Income for 2004 decreased $1 million primarily due to:
o A decrease in Sales to AEP Affiliates of $2 million due to a decline in
available power caused by a planned plant outage at Rockport Unit 2 in early
February through March of 2004. Our share of Rockport's generation was down
30% in the first quarter of 2004 compared to 2003.
o Fuel expense was up $3 million over 2003 due to increased generation based
on increased plant availability at Big Sandy in 2004 resulting from
unplanned outages at Big Sandy in 2003.
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 A $1 million increase in Other Operation expense primarily due to increased
employee-related expenses in 2004.
o A $1 million decrease in gains from risk management activities included in
Operating Income.
The decreases in Operating Income were partially offset by:
o An increase in retail revenues of $2 million over 2003 due to the rate
increase in mid 2003 to recover the cost of emission control equipment.
o An increase in off-system sales and transmission revenues of $1 million.
o A decrease in Purchased Electricity from AEP Affiliates of $4 million due to
increased purchases in 2003 driven by unplanned outages at the Big Sandy
plant in 2003. In addition, energy purchases decreased from the Rockport
Plant due to the planned outage at Rockport Unit 2 discussed above. Our
energy purchases from Rockport are based on plant availability, as required
by the unit power agreement with AEGCo, an affiliated company. The unit power
agreement with AEGCo provides for our purchase of 15% of the total output of
the two unit 2,600-MW capacity Rockport Plant.
Other Impacts on Earnings
- -------------------------
Nonoperating Income (Loss) increased $3 million in the first quarter of 2004
compared to 2003 primarily due to favorable results from risk management
activities for power sold outside AEP's traditional marketing area resulting
from AEP's plan to exit risk management activities in areas outside of its
traditional market area.
Nonoperating Expenses increased $1 million due to a loss on the sale of land
associated with the Ashland general office building in the first quarter of
2004.
Interest Charges increased $1 million primarily due to reduced allowance for
funds used during construction in 2004 resulting from the completion of the
emission control equipment in mid 2003.
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 three
months of 2004.
Significant Factors
- -------------------
See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.
Critical Accounting Policies
- ----------------------------
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
Three Months Ended March 31, 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) (2,407)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 246
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) 1,399
Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) 2,380
--------
Total MTM Risk Management Contract Net Assets 17,108
Net Cash Flow Hedge Contracts (f) (1,003)
DETM Assignment (g) (6,831)
--------
Total MTM Risk Management Contract Net Assets at March 31, 2004 $9,274
========
(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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ---- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(1,186) $540 $(22) $189 $- $- $(479)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 5,564 3,312 1,452 513 269 - 11,110
Prices Based on Models and Other
Valuation Methods (b) (27) 61 993 1,336 1,313 2,801 6,477
-------- ------- ------- ------- ------- ------- --------
Total $4,351 $3,913 $2,423 $2,038 $1,582 $2,801 $17,108
======== ======= ======= ======= ======= ======= ========
(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
- --------------------------------------------------------------------------
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, the table does not provide a full
picture of our hedging activity. In accordance with GAAP, all amounts are
presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2004
Power Interest Rate Consolidated
----- ------------- ------------
(in thousands)
Beginning Balance December 31, 2003 $82 $338 $420
Changes in Fair Value (a) (673) - (673)
Reclassifications from AOCI to Net
Income (b) (60) (21) (81)
------ ----- ------
Ending Balance March 31, 2004 $(651) $317 $(334)
====== ===== ======
(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 $215 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:
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
--------------------------------------- ------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$158 $498 $273 $139 $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 $23 million and $29 million at March 31, 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 Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $106,901 $103,959
Sales to AEP Affiliates 6,612 8,135
--------- --------
TOTAL 113,513 112,094
--------- --------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 20,894 17,947
Purchased Electricity from AEP Affiliates 33,306 37,395
Other Operation 13,248 12,137
Maintenance 7,325 6,765
Depreciation and Amortization 10,859 8,712
Taxes Other Than Income Taxes 2,328 2,365
Income Taxes 6,460 6,939
--------- --------
TOTAL 94,420 92,260
--------- --------
OPERATING INCOME 19,093 19,834
Nonoperating Income (Loss) 952 (2,398)
Nonoperating Expenses 1,313 249
Nonoperating Income Tax Credit (127) (558)
Interest Charges 7,369 6,724
--------- --------
Income Before Cumulative Effect of Accounting Change 11,490 11,021
Cumulative Effect of Accounting Change (Net of Tax) - (1,134)
--------- --------
NET INCOME $11,490 $9,887
========= =========
The common stock of KPCo is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 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 (5,482) (5,482)
---------
TOTAL 292,536
---------
COMPREHENSIVE INCOME
- --------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (2,865) (2,865)
NET INCOME 9,887 9,887
---------
TOTAL COMPREHENSIVE INCOME 7,022
-------- --------- -------- --------- ---------
MARCH 31, 2003 $50,450 $208,750 $52,674 $(12,316) $299,558
======== ========= ======== ========= =========
DECEMBER 31, 2003 $50,450 $208,750 $64,151 $(6,213) $317,138
Common Stock Dividends (6,250) (6,250)
---------
TOTAL 310,888
---------
COMPREHENSIVE INCOME
- --------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (754) (754)
NET INCOME 11,490 11,490
---------
TOTAL COMPREHENSIVE INCOME 10,736
-------- --------- -------- --------- ---------
MARCH 31, 2004 $50,450 $208,750 $69,391 $(6,967) $321,624
======== ========= ======== ========= =========
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ------------------------------------------------------
Production $458,081 $457,341
Transmission 381,584 381,354
Distribution 429,586 425,688
General 58,078 68,041
Construction Work in Progress 14,026 17,322
----------- -----------
TOTAL 1,341,355 1,349,746
Accumulated Depreciation and Amortization 378,202 381,876
----------- -----------
TOTAL - NET 963,153 967,870
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ------------------------------------------------------
Non-Utility Property, Net 5,421 5,423
Other Investments 806 1,022
----------- -----------
TOTAL 6,227 6,445
----------- -----------
CURRENT ASSETS
- ------------------------------------------------------
Cash and Cash Equivalents 1,234 886
Advances to Affiliates 13,142 -
Accounts Receivable:
Customers 15,710 21,177
Affiliated Companies 20,237 25,327
Accrued Unbilled Revenues 7,083 5,534
Miscellaneous 287 97
Allowance for Uncollectible Accounts (120) (736)
Fuel 10,776 9,481
Materials and Supplies 20,610 16,585
Risk Management Assets 22,435 16,200
Margin Deposits 1,594 2,660
Prepayments and Other 1,866 1,696
----------- -----------
TOTAL 114,854 98,907
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 101,799 99,828
Other Regulatory Assets 15,764 13,971
Long-term Risk Management Assets 22,269 16,134
Deferred Property Taxes 5,267 6,847
Other Deferred Charges 11,496 11,632
----------- -----------
TOTAL 156,595 148,412
----------- -----------
TOTAL ASSETS $1,240,829 $1,221,634
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
CAPATALIZATION AND LIABILITIES
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
CAPITALIZATION
- -------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $50,450 $50,450
Paid-in Capital 208,750 208,750
Retained Earnings 69,391 64,151
Accumulated Other Comprehensive Income (Loss) (6,967) (6,213)
----------- -----------
Total Common Shareholder's Equity 321,624 317,138
----------- -----------
Long-term Debt:
Nonaffiliated 427,625 427,602
Affiliated 80,000 60,000
----------- -----------
Total Long-term Debt 507,625 487,602
----------- -----------
TOTAL 829,249 804,740
----------- -----------
CURRENT LIABILITIES
- -------------------------------------------------------
Advances from Affiliates - 38,096
Accounts Payable:
General 23,162 22,802
Affiliated Companies 25,554 22,648
Customer Deposits 12,458 9,894
Taxes Accrued 12,356 7,329
Interest Accrued 8,886 6,915
Risk Management Liabilities 19,111 11,704
Obligations Under Capital Leases 1,650 1,743
Other 7,530 8,628
----------- -----------
TOTAL 110,707 129,759
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- -------------------------------------------------------
Deferred Income Taxes 217,127 212,121
Regulatory Liabilities:
Asset Removal Costs 28,204 26,140
Deferred Investment Tax Credits 7,662 7,955
Other Regulatory Liabilities 14,302 10,591
Long-term Risk Management Liabilities 16,319 12,363
Obligations Under Capital Leases 2,933 3,549
Deferred Credits and Other 14,326 14,416
----------- -----------
TOTAL 300,873 287,135
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $1,240,829 $1,221,634
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------
Net Income $11,490 $9,887
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change - 1,134
Depreciation and Amortization 10,859 8,712
Deferred Income Taxes 3,442 2,766
Deferred Investment Tax Credits (292) (294)
Deferred Fuel Costs, Net (988) (388)
Loss on Sale of Assets 1,051 -
Mark-to-Market of Risk Management Contracts (2,135) 3,500
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 8,202 5,776
Fuel, Materials and Supplies (5,320) (1,339)
Accounts Payable 3,266 (25,204)
Taxes Accrued 5,027 9,932
Change in Other Assets (2,280) (474)
Change in Other Liabilities 11,362 2,765
-------- --------
Net Cash Flows From Operating Activities 43,684 16,773
-------- --------
INVESTING ACTIVITIES
- ------------------------------------------------------
Construction Expenditures (7,386) (35,025)
Proceeds from Sales of Property and Other 1,538 210
-------- --------
Net Cash Flow Used for Investing Activities (5,848) (34,815)
-------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------
Issuance of Long-term Debt - Affiliated 20,000 -
Change in Advances to/from Affiliates, Net (51,238) 22,685
Dividends Paid (6,250) (5,482)
-------- --------
Net Cash Flows From (Used For) Financing Activities (37,488) 17,203
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 348 (839)
Cash and Cash Equivalents at Beginning of Period 886 2,304
-------- --------
Cash and Cash Equivalents at End of Period $1,234 $1,465
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $5,104,000 and $7,975,000 and for income taxes was $(833,000)
and $(6,435,000) in 2004 and 2003, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
The notes to KPCo's financial statements are combined with the notes to
respective 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 $114 million primarily due to a $125 million Cumulative
Effect of Accounting Changes in the first quarter of 2003. Income Before
Cumulative Effect increased $11 million primarily due to an increase in risk
management income.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income increased $9 million for the three months ended March 31, 2004
compared with the three months ended March 31, 2003 due to:
o A $7 million increase in retail revenue primarily due to growth in the
residential and commercial customer base.
o A $7 million increase in Sales to AEP Affiliates. The increase is
primarily the result of a 19.0% increase in MWH for affiliated
system sales partially offset by lower price realizations for this
year. In addition, the increase in Sales to AEP Affiliates is also
the result of optimizing our generation capacity and selling our
excess generated power to the AEP Power Pool.
o A $7 million decrease in Purchased Electricity for Resale. This
decrease was 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, which was included in rates for the first
quarter of 2003, was no longer in effect for 2004.
o A $19 million decrease in Income Taxes. This decrease was primarily due to
a decrease in pre-tax operating book income and tax adjustments recorded
in 2003.
The increase in Operating Income was partially offset by:
o A $7 million decrease in non-affiliated sales for resale primarily
as a result of a 13.4% decrease in MWH sales. In addition, there
were no Ohio Edison interchange revenues recorded during 2004 as a
result of the cessation of the Buckeye Transmission agreement
discussed above with no effect to net income as a result of the
cessation.
o A $13 million increase in Fuel for Electric Generation due to a
9.7% increase in the number of tons consumed during the first
quarter of 2004. In addition, generation increased 11.1% from the
first quarter of 2003 to the first quarter of 2004.
o A $10 million increase in Depreciation and Amortization 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 a corresponding quarterly adjustment to the amortization
amount.
Other Impacts of Earnings
- -------------------------
Nonoperating Income increased $20 million primarily due to favorable results
from risk management activities in the first quarter of 2004 compared to losses
that were incurred in the first quarter of 2003.
Nonoperating Income Tax Expense (Credit) increased $10 million as a result of an
increase in pre-tax nonoperating book income.
Interest charges increased $11 million due primarily to the consolidation of JMG
and its associated debt along with replacement of lower cost floating-rate
short-term debt with higher cost fixed-rate long-term debt (there was no change
in overall net income due to the consolidation of JMG).
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 three months ended March 31, 2004 and 2003 were as follows:
2004 2003
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $58,250 $5,285
--------- --------
Cash flows from (used for):
Operating activities 125,431 35,390
Investing activities (49,066) (54,739)
Financing activities (123,792) 46,476
--------- --------
Net increase (decrease) in cash and cash equivalents (47,427) 27,127
--------- --------
Cash and cash equivalents at end of period $10,823 $32,412
========= ========
Operating Activities
- --------------------
Cash Flows From Operating Activities for the first quarter of 2004 increased $90
million compared to the first quarter of 2003. This is primarily due to
significant reductions in Accounts Payable balances during the first quarter of
2003 partially associated with a wind-down of risk management activities in that
year.
Investing Activities
- --------------------
Cash Flows Used For Investing Activities were reduced by $6 million during the
first quarter of 2004 compared with the first quarter of 2003 due primarily to a
decrease in construction expenditures.
Financing Activities
- --------------------
Cash Flows For Financing Activities used $124 million in the first quarter of
2004 and provided $46 million in the first quarter of 2003. This is primarily
due to a decrease in the change in Advances to/from Affiliates, Net, during the
first quarter 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 three months of 2004
were:
Issuances
---------
None
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 1,463 6.81 2008
Other
- -----
Power Generation Facility
- -------------------------
AEP has agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, own and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
AEP. The Facility is a "qualifying cogeneration facility" for purposes of PURPA.
Commercial operation of the Facility as required by the agreements between
Juniper, AEP and The Dow Chemical Company (Dow) was achieved on March 18, 2004.
The initial term of the lease commenced on March 18, 2004, and AEP may extend
the lease term for up to 30 years. The lease of the Facility is reported by AEP
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.
Juniper arranged to finance the Facility with debt financing up to $494 million
and equity up to $31 million from investors with no relationship to AEP or any
of AEP's subsidiaries.
At March 31, 2004, Juniper's acquisition costs for the Facility totaled $516
million, and AEP estimates total costs for the completed Facility to be
approximately $525 million. For the 30-year extended lease term, the majority of
base lease rental is a variable rate obligation indexed to three-month LIBOR
(1.11% as of March 31, 2004). Consequently, as market interest rates increase,
the base rental payments under the lease will also increase. An additional
rental prepayment (up to $396 million) may be due on June 30, 2004 unless
Juniper has refinanced its present debt financing on a long-term basis. Juniper
is currently planning to refinance by June 30, 2004. The Facility is collateral
for the debt obligation of Juniper. At March 31, 2004 and December 31, 2003, AEP
reflected $396 million as long-term debt due within one year. AEP's maximum
required cash payment as a result of their financing transaction with Juniper is
$396 million as well as interest payments during the lease term. Due to the
treatment of the Facility as a financing of an owned asset, the recorded
liability of $516 million is greater than AEP's maximum possible cash payment
obligation to Juniper.
Dow will use a portion of the energy produced by the Facility and sell the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of such
excess energy from Dow. 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.
OPCo has entered into 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.
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. AEP
alleges 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, AEP 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 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.
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 "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.
Critical Accounting Policies
- ----------------------------
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
Three Months Ended March 31, 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) (8,659)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 855
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) 13,146
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) -
--------
Total MTM Risk Management Contract Net Assets 59,280
Net Cash Flow Hedge Contracts (f) (3,474)
DETM Assignment (g) (23,670)
--------
Total MTM Risk Management Contracts Net Assets at March 31, 2004 $32,136
========
(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 Consolidated Statements of
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(f)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
Accumulated Other Comprehensive Income (Loss).
(g)See Note 17 "Related Party Transactions" in the 2003 Annual Report.
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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(4,109) $1,873 $(75) $654 $- $- $(1,657)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 19,279 11,476 5,033 1,779 931 - 38,498
Prices Based on Models and Other
Valuation Methods (b) (103) 212 3,443 4,632 4,551 9,704 22,439
-------- -------- ------ ------- ------- ------- --------
Total $15,067 $13,561 $8,401 $7,065 $5,482 $9,704 $59,280
======== ======== ======= ======= ======= ======= ========
(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
- --------------------------------------------------------------------------
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, the table does not provide a full
picture of our hedging activity. In accordance with GAAP, all amounts are
presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2004
Foreign
Power Currency Consolidated
----- -------- ------------
(in thousands)
Beginning Balance December 31, 2003 $268 $(371) $(103)
Changes in Fair Value (a) (2,306) - (2,306)
Reclassifications from AOCI to Net
Income (b) (219) 3 (216)
-------- ------ --------
Ending Balance March 31, 2004 $(2,257) $(368) $(2,625)
======== ====== ========
(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 $1,058 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:
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
-------------------------------------- --------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$546 $1,726 $945 $480 $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 $161 million and $214 million at March 31, 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 Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES
- ---------------------------------------------------
Electric Generation, Transmission and Distribution $443,218 $450,887
Sales to AEP Affiliates 146,488 139,744
--------- ---------
TOTAL 589,706 590,631
--------- ---------
OPERATING EXPENSES
- ---------------------------------------------------
Fuel for Electric Generation 166,271 153,648
Purchased Electricity for Resale 12,183 19,392
Purchased Electricity from AEP Affiliates 19,303 22,783
Other Operation 91,305 92,981
Maintenance 34,051 35,457
Depreciation and Amortization 71,782 61,551
Taxes Other Than Income Taxes 47,190 47,155
Income Taxes 39,982 58,794
--------- ---------
TOTAL 482,067 491,761
--------- ---------
OPERATING INCOME 107,639 98,870
Nonoperating Income (Loss) 16,930 (2,724)
Nonoperating Expenses 8,069 11,710
Nonoperating Income Tax Expense (Credit) 5,087 (4,656)
Interest Charges 31,969 20,742
--------- ---------
Income Before Cumulative Effect of Accounting Changes 79,444 68,350
Cumulative Effect of Accounting Changes (Net of Tax) - 124,632
--------- ---------
NET INCOME 79,444 192,982
Preferred Stock Dividend Requirements 183 314
--------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $79,261 $192,668
========= =========
The common stock of OPCo is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 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 (41,934) (41,934)
Preferred Stock Dividends (314) (314)
-----------
TOTAL 1,190,866
-----------
COMPREHENSIVE INCOME
- ------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (4,115) (4,115)
NET INCOME 192,982 192,982
-----------
TOTAL COMPREHENSIVE INCOME 188,867
--------- --------- --------- --------- -----------
MARCH 31, 2003 $321,201 $462,483 $673,050 $(77,001) $1,379,733
========= ========= ========= ========= ===========
DECEMBER 31, 2003 $321,201 $462,484 $729,147 $(48,807) $1,464,025
Common Stock Dividends (57,057) (57,057)
Preferred Stock Dividends (183) (183)
-----------
TOTAL 1,406,785
-----------
COMPREHENSIVE INCOME
- ------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (2,522) (2,522)
Minimum Pension Liability (3,942) (3,942)
NET INCOME 79,444 79,444
-----------
TOTAL COMPREHENSIVE INCOME 72,980
--------- --------- --------- --------- -----------
MARCH 31, 2004 $321,201 $462,484 $751,351 $(55,271) $1,479,765
========= ========= ========= ========= ===========
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ------------------------------------------------------
Production $4,047,851 $4,029,515
Transmission 948,046 938,805
Distribution 1,168,305 1,156,886
General 249,904 245,434
Construction Work in Progress 147,349 160,675
----------- -----------
Total 6,561,455 6,531,315
Accumulated Depreciation and Amortization 2,515,726 2,485,947
----------- -----------
TOTAL - NET 4,045,729 4,045,368
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ------------------------------------------------------
Non-Utility Property, Net 29,211 29,291
Other 22,774 24,264
----------- -----------
TOTAL 51,985 53,555
----------- -----------
CURRENT ASSETS
- ------------------------------------------------------
Cash and Cash Equivalents 10,823 58,250
Advances to Affiliates, Net 139,888 67,918
Accounts Receivable:
Customers 87,362 100,960
Affiliated Companies 145,088 120,532
Accrued Unbilled Revenues 18,895 17,221
Miscellaneous 1,374 736
Allowance for Uncollectible Accounts (173) (789)
Fuel 74,876 77,725
Materials and Supplies 102,631 92,136
Risk Management Assets 77,740 56,265
Margin Deposits 5,749 9,296
Prepayments and Other 16,836 15,883
----------- -----------
TOTAL 681,089 616,133
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 170,020 169,605
Transition Regulatory Assets 287,903 310,035
Unamortized Loss on Reacquired Debt 11,305 10,172
Other 22,869 22,506
Long-term Risk Management Assets 77,163 52,825
Deferred Property Taxes 52,723 67,469
Deferred Charges and Other Assets 28,145 26,850
----------- -----------
TOTAL 650,128 659,462
----------- -----------
TOTAL ASSETS $5,428,931 $5,374,518
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 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 751,351 729,147
Accumulated Other Comprehensive Income (Loss) (55,271) (48,807)
----------- -----------
Total Common Shareholder's Equity 1,479,765 1,464,025
Cumulative Preferred Stock Not Subject to Mandatory Redemption 16,645 16,645
----------- -----------
Total Shareholder's Equity 1,496,410 1,480,670
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption 5,000 7,250
Long-term Debt:
Nonaffiliated 1,605,905 1,608,086
Affiliated 200,000 -
----------- -----------
Total Long-term Debt 1,805,905 1,608,086
----------- -----------
TOTAL 3,307,315 3,096,006
----------- -----------
Minority Interest 15,721 16,314
----------- -----------
CURRENT LIABILITIES
- ------------------------------------------------------------------------
Short-term Debt - General 26,572 25,941
Long-term Debt Due Within One Year - Nonaffiliated 243,604 431,854
Accounts Payable:
General 100,524 104,874
Affiliated Companies 84,434 101,758
Customer Deposits 27,588 17,308
Taxes Accrued 151,129 132,793
Interest Accrued 28,745 45,679
Risk Management Liabilities 66,220 38,318
Obligations Under Capital Leases 9,106 9,624
Other 59,721 71,642
----------- -----------
TOTAL 797,643 979,791
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ------------------------------------------------------------------------
Deferred Income Taxes 938,218 933,582
Regulatory Liabilities:
Asset Removal Costs 104,405 101,160
Deferred Investment Tax Credits 14,880 15,641
Other - 3
Long-term Risk Management Liabilities 56,547 40,477
Deferred Credits 24,801 23,222
Obligations Under Capital Leases 22,672 25,064
Asset Retirement Obligations 43,489 42,656
Other 103,240 100,602
----------- -----------
TOTAL 1,308,252 1,282,407
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $5,428,931 $5,374,518
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- --------------------------------------------------------
Net Income $79,444 $192,982
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes - (124,632)
Depreciation and Amortization 71,782 61,551
Deferred Income Taxes 7,701 (1,563)
Deferred Property Taxes 15,250 14,878
Mark-to-Market of Risk Management Contracts (5,729) 14,156
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (13,886) 6,055
Fuel, Materials and Supplies (7,646) 13,541
Prepayments and Other 2,594 (24,288)
Accounts Payable (21,674) (108,723)
Customer Deposits 10,280 7,025
Taxes Accrued 18,336 53,444
Interest Accrued (16,934) 5,835
Change in Other Assets (3,084) (50,720)
Change in Other Liabilities (11,003) (24,151)
--------- ---------
Net Cash Flows From Operating Activities 125,431 35,390
--------- ---------
INVESTING ACTIVITIES
- --------------------------------------------------------
Construction Expenditures (50,188) (56,372)
Proceeds from Sale of Property and Other 1,122 1,633
--------- ---------
Net Cash Flows Used For Investing Activities (49,066) (54,739)
--------- ---------
FINANCING ACTIVITIES
- --------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated - 494,375
Issuance of Long-term Debt - Affiliated 200,000 -
Change in Advances to/from Affiliates, Net (71,970) 109,349
Change in Short-term Debt, Net 631 -
Change in Short-term Debt - Affiliates, Net - (275,000)
Retirement of Long-term Debt - Nonaffiliated (192,963) -
Retirement of Long-term Debt - Affiliated - (240,000)
Retirement of Cumulative Preferred Stock (2,250) -
Dividends Paid on Common Stock (57,057) (41,934)
Dividends Paid on Cumulative Preferred Stock (183) (314)
--------- ---------
Net Cash Flows (Used For) From Financing Activities (123,792) 46,476
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (47,427) 27,127
Cash and Cash Equivalents at Beginning of Period 58,250 5,285
--------- ---------
Cash and Cash Equivalents at End of Period $10,823 $32,412
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $46,636,000 and $14,551,000 and for income taxes was
$(8,664,000) and $(22,475,000) in 2004 and 2003, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
The notes to OPCo's financial statements are combined with the notes to
respective 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 $10 million for the quarter due mainly to increased Other
Operation expenses.
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.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income decreased $13 million primarily due to:
o Decreased non-fuel related revenues of $3 million, due mainly to a $2
million decrease in wholesale margins from decreased off-system KWH sales.
o Increased Other Operation expenses of $12 million due mainly to increased
affiliated ancillary services and OATT resulting from an adjustment for
prior years due to revised data from ERCOT for the years 2001-2003 of $5
million, other transmission related expenses, increased administrative
expenses largely due to outside services and employee related expenses.
o Increased Maintenance expense of $4 million due mainly to increased scheduled
power plant maintenance of $3 million.
.
The decrease in Operating Income was partially offset by:
o Decreased income taxes of $7 million is due primarily to a decrease in
pre-tax operating book income.
Other Impacts on Earnings
- -------------------------
Interest Charges decreased $3 million as a result of the replacement of higher
interest rate first mortgage bonds in 2003 with lower fixed-rate senior
unsecured debt.
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 Baa1 BBB A-
Financing Activity
- ------------------
There were no long-term debt issuances or retirements during the first three
months of 2004.
Significant Factors
- -------------------
See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.
Critical Accounting Policies
- ----------------------------
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
Three Months Ended March 31, 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) (1,039)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 109
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) (9,099)
--------
Total MTM Risk Management Contract Net Assets 4,028
Net Cash Flow Hedge Contracts (f) (442)
--------
Total MTM Risk Management Contract Net Assets at March 31, 2004 $3,586
========
(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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted -
Exchange Traded Contracts $(523) $238 $(10) $83 $- $- $(212)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 1,850 1,140 29 - - - 3,019
Prices Based on Models and Other
Valuation Methods (b) (66) (128) 85 215 335 780 1,221
------- ------- ----- ----- ----- ----- -------
Total $1,261 $1,250 $104 $298 $335 $780 $4,028
======= ======= ===== ===== ===== ===== =======
(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
- --------------------------------------------------------------------------
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, the table does not provide a full
picture of our hedging activity. In accordance with GAAP, all amounts are
presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2004
(in thousands)
Beginning Balance December 31, 2003 $156
Changes in Fair Value (a) (416)
Reclassifications from AOCI to Net Income (b) (28)
------
Ending Balance March 31, 2004 $(288)
======
(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 $133 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:
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
--------------------------------------- ---------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$70 $220 $120 $61 $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 $56 million and $66 million at March 31, 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 Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $204,043 $238,267
Sales to AEP Affiliates 3,142 4,395
--------- ---------
TOTAL 207,185 242,662
--------- ---------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 89,085 103,174
Purchased Electricity for Resale 9,168 12,491
Purchased Electricity from AEP Affiliates 26,899 42,107
Other Operation 43,676 31,618
Maintenance 13,122 9,394
Depreciation and Amortization 22,176 21,494
Taxes Other Than Income Taxes 9,817 9,646
Income Taxes (Credits) (7,333) (408)
--------- ---------
TOTAL 206,610 229,516
--------- ---------
OPERATING INCOME 575 13,146
Nonoperating Income 244 650
Nonoperating Expense 542 439
Nonoperating Income Tax Credit 392 200
Interest Charges 9,953 12,866
--------- ---------
NET INCOME (LOSS) (9,284) 691
Preferred Stock Dividend Requirements 53 53
--------- ---------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $(9,337) $638
========= =========
The common stock of PSO is owned by a wholly-owned subsidiary of AEP.
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 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
Common Stock Dividends (7,500) (7,500)
Preferred Stock Dividends (53) (53)
Distribution of Investment in AEMT, Inc.
Preferred Shares to Parent (548) (548)
---------
TOTAL 391,146
---------
COMPREHENSIVE INCOME (LOSS)
- ------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,197) (1,197)
Minimum Pension Liability (58) (58)
NET INCOME 691 691
---------
TOTAL COMPREHENSIVE INCOME (LOSS) (564)
--------- --------- --------- --------- ---------
MARCH 31, 2003 $157,230 $180,016 $109,064 $(55,728) $390,582
========= ========= ========= ========= =========
DECEMBER 31, 2003 $157,230 $230,016 $139,604 $(43,842) $483,008
Common Stock Dividends (8,750) (8,750)
Preferred Stock Dividends (53) (53)
---------
TOTAL 474,205
---------
COMPREHENSIVE INCOME (LOSS)
- ------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (444) (444)
NET LOSS (9,284) (9,284)
---------
TOTAL COMPREHENSIVE INCOME (LOSS) (9,728)
--------- --------- --------- --------- ---------
MARCH 31, 2004 $157,230 $230,016 $121,517 $(44,286) $464,477
========= ========= ========= ========= =========
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ----------------------------------------------------
Production $1,067,554 $1,065,408
Transmission 451,920 451,292
Distribution 1,054,116 1,031,229
General 206,951 203,756
Construction Work in Progress 35,041 54,711
----------- -----------
TOTAL 2,815,582 2,806,396
Accumulated Depreciation and Amortization 1,082,327 1,069,216
----------- -----------
TOTAL - NET 1,733,255 1,737,180
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ----------------------------------------------------
Non-Utility Property, Net 4,388 4,631
Other Investments 2,320 2,320
----------- -----------
TOTAL 6,708 6,951
----------- -----------
CURRENT ASSETS
- ----------------------------------------------------
Cash and Cash Equivalents 8,918 14,258
Accounts Receivable:
Customers 27,280 28,515
Affiliated Companies 15,845 19,852
Miscellaneous 1,189 -
Allowance for Uncollectible Accounts (38) (37)
Fuel Inventory 16,770 18,331
Materials and Supplies 39,064 38,125
Regulatory Asset for Under-recovered Fuel Costs 19,772 24,170
Risk Management Assets 6,422 18,586
Margin Deposits 3,936 4,351
Prepayments and Other 3,444 2,655
----------- -----------
TOTAL 142,602 168,806
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ----------------------------------------------------
Regulatory Assets:
Unamortized Loss on Reacquired Debt 13,885 14,357
Other 13,044 14,342
Long-term Risk Management Assets 4,418 10,379
Deferred Charges 43,801 18,017
----------- -----------
TOTAL 75,148 57,095
----------- -----------
TOTAL ASSETS $1,957,713 $1,970,032
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 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 121,517 139,604
Accumulated Other Comprehensive Income (Loss) (44,286) (43,842)
----------- -----------
Total Common Shareholder's Equity 464,477 483,008
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,267 5,267
----------- -----------
Total Shareholder's Equity 469,744 488,275
Long-term Debt 413,314 490,598
----------- -----------
TOTAL 883,058 978,873
----------- -----------
CURRENT LIABILITIES
- ---------------------------------------------------------------
Long-term Debt Due Within One Year 161,020 83,700
Advances from Affiliates 47,642 32,864
Accounts Payable:
General 46,203 48,808
Affiliated Companies 52,071 57,206
Customer Deposits 28,904 26,547
Taxes Accrued 44,581 27,157
Interest Accrued 3,738 3,706
Risk Management Liabilities 4,906 11,067
Obligations Under Capital Leases 464 452
Other 30,661 35,234
----------- -----------
TOTAL 420,190 326,741
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- ---------------------------------------------------------------
Deferred Income Taxes 335,348 335,434
Long-Term Risk Management Liabilities 2,348 3,602
Regulatory Liabilities:
Asset Removal Costs 216,517 214,033
Deferred Investment Tax Credits 29,963 30,411
SFAS 109 Regulatory Liability, Net 24,296 24,937
Other 5,508 15,406
Obligations Under Capital Leases 576 558
Deferred Credits and Other 39,909 40,037
----------- -----------
TOTAL 654,465 664,418
----------- -----------
Commitments and Contingencies (Note 5)
$1,957,713 $1,970,032
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------------
Net Income (Loss) $(9,284) $691
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows
From Operating Activities:
Depreciation and Amortization 22,176 21,494
Deferred Income Taxes 456 1,309
Deferred Investment Tax Credits (448) (447)
Deferred Property Taxes (25,943) (24,413)
Mark-to-Market of Risk Management Contracts 10,029 (1,412)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 4,054 (769)
Fuel, Materials and Supplies 622 229
Accounts Payable (7,740) (4,822)
Taxes Accrued 17,424 15,878
Fuel Recovery 4,398 (1,231)
Changes in Other Assets (2,115) (6,590)
Changes in Other Liabilities (10,604) (9,266)
-------- --------
Net Cash Flows From (Used For) Operating Activities 3,025 (9,349)
-------- --------
INVESTING ACTIVITIES
- ------------------------------------------------------------
Construction Expenditures (14,584) (17,612)
Proceeds from Sale of Property and Other 244 -
-------- --------
Net Cash Flows Used For Investing Activities (14,340) (17,612)
-------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------------
Change in Advances to/from Affiliates, Net 14,778 33,715
Dividends Paid on Common Stock (8,750) (7,500)
Dividends Paid on Cumulative Preferred Stock (53) (53)
-------- --------
Net Cash Flows From Financing Activities 5,975 26,162
-------- --------
Net Decrease in Cash and Cash Equivalents (5,340) (799)
Cash and Cash Equivalents at Beginning of Period 14,258 16,774
-------- --------
Cash and Cash Equivalents at End of Period $8,918 $15,975
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $8,951,000 and $9,653,000 and for income taxes was $(2,695,000)
and $(959,000) 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 Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
The notes to PSO's financial statements are combined with the notes to
respective 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 $14 million for 2004 due largely to the $9 million (net of
tax) Cumulative Effect of Accounting Changes recorded in 2003.
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.
First Quarter 2004 Compared to First Quarter 2003
- -------------------------------------------------
Operating Income
- ----------------
Operating Income decreased by $6 million primarily due to:
o A decrease in risk management activities of $4 million.
o Increased Other Operations expense of $12 million primarily due to
an increase related to transmission expense resulting from a prior
year true-up for OATT transactions recorded in 2004 resulting from
revised data from ERCOT for the years 2001-2003 of $6 million and
a $5 million increase related to deferred fuel for the Louisiana
jurisdiction.
o Increased Maintenance expense of $3 million primarily related to scheduled
power plant maintenance offset in part by lower overhead line expense.
o Increased Depreciation and Amortization expense of $3 million due primarily
to the restoration in 2003 of a regulatory asset related to the recovery
of fuel related costs in Arkansas.
The decrease in Operating Income was partially offset by:
o An increase in retail base revenues of $4 million due to an
increased number of customers and their average usage, offset in
part by milder weather resulting from a 3% decrease in degree-days.
o A $2 million increase in transmission revenues due mainly to a prior year
true-up for OATT transactions recorded in 2004 resulting from revised data
from ERCOT for the years 2001-2003.
o Decreased Income Taxes of $5 million is due primarily to a decrease in
pre-tax operating book income.
Other Impacts on Earnings
- -------------------------
Minority Interest Expense of $1 million is a result of consolidating Sabine
Mining Company during the third quarter of 2003, due to implementation of FIN
46.
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.
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 Baa1 BBB A-
Cash Flow
- ---------
Cash flows for the Three Months ended March 31, 2004 and 2003 were as follows:
2004 2003
---- ----
Cash and cash equivalents at beginning of period $11,724 $2,069
-------- --------
Cash flows from (used for):
Operating activities 17,180 24,334
Investing activities (19,664) (25,418)
Financing activities 56,959 6,178
-------- --------
Net increase (decrease) in cash and cash equivalents 54,475 5,094
-------- --------
Cash and cash equivalents at end of period $66,199 $7,163
======== ========
Operating Activities
- --------------------
Cash Flows From Operating Activities were $17 million primarily due to Net
Income, Accounts Receivables, Fuel Recovery and Taxes Accrued.
Investing Activities
- --------------------
Cash Used for Investing Activities was primarily related to construction
projects for improved transmission and distribution service reliability.
Financing Activities
- --------------------
Cash Flows From 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 three months of 2004
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
Installment Purchase Contracts $53,500 Variable 2019
In the second quarter of 2004, the funds from the issuance of the installment
purchase contracts were used to redeem the $53.5 million, 7.60% DeSoto
installment purchase contracts due 2019.
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in thousands) (%)
First Mortgage Bonds $80,000 6.875 2025
Installment Purchase Contracts 450 6.0 2008
Notes Payable 1,707 4.47 2011
Notes Payable 750 Variable 2008
Significant Factors
- -------------------
See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.
Critical Accounting Policies
- ----------------------------
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
Three Months Ended March 31, 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) (3,297)
Fair Value of New Contracts When Entered Into During the Period (b) -
Net Option Premiums Paid/(Received) (c) 128
Change in Fair Value Due to Valuation Methodology Changes -
Changes in Fair Value of Risk Management Contracts (d) (1,750)
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) (6,920)
--------
Total MTM Risk Management Contract Net Assets 4,767
Net Cash Flow Hedge Contracts (f) (1,557)
--------
Total MTM Risk Management Contract Net Assets at March 31, 2004 $3,210
========
(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
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).
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 March 31, 2004
Remainder After
2004 2005 2006 2007 2008 2008 Total (c)
--------- ---- ---- ---- ---- ----- ---------
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(616) $281 $(11) $98 $- $- $(248)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 2,178 1,342 34 (1) - - 3,553
Prices Based on Models and Other
Valuation Methods (b) (51) (150) 99 253 394 917 1,462
------- ------- ----- ----- ----- ----- -------
Total $1,511 $1,473 $122 $350 $394 $917 $4,767
======= ======= ===== ===== ===== ===== =======
(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
- --------------------------------------------------------------------------
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, the table does not provide a full
picture of our hedging activity. In accordance with GAAP, all amounts are
presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2004
(in thousands)
Beginning Balance December 31, 2003 $184
Changes in Fair Value (a) (490)
Reclassifications from AOCI to Net Income (b) (32)
------
Ending Balance March 31, 2004 $(338)
======
(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 an $156 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:
Three Months Ended Twelve Months Ended
March 31, 2004 December 31, 2003
-------------------------------------- ----------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$82 $259 $142 $72 $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 $37 million and $57 million at March 31, 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 Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------
Electric Generation, Transmission and Distribution $213,949 $223,614
Sales to AEP Affiliates 22,211 31,664
--------- ---------
TOTAL 236,160 255,278
--------- ---------
OPERATING EXPENSES
- --------------------------------------------------
Fuel for Electric Generation 86,738 103,010
Purchased Electricity for Resale 5,934 12,567
Purchased Electricity from AEP Affiliates 7,307 10,810
Other Operation 52,644 40,857
Maintenance 15,648 12,817
Depreciation and Amortization 31,285 28,035
Taxes Other Than Income Taxes 16,567 15,873
Income Taxes 131 5,265
--------- ---------
TOTAL 216,254 229,234
--------- ---------
OPERATING INCOME 19,906 26,044
Nonoperating Income 1,403 872
Nonoperating Expenses 826 521
Nonoperating Income Tax Expense (Credit) (356) 50
Interest Charges 15,228 15,854
Minority Interest (881) -
--------- ---------
Income Before Cumulative Effect of Accounting Changes 4,730 10,491
Cumulative Effect of Accounting Changes (Net of Tax) - 8,517
--------- ---------
NET INCOME 4,730 19,008
Preferred Stock Dividend Requirements 57 57
--------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $4,673 $18,951
========= =========
The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 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 (18,199) (18,199)
Preferred Stock Dividends (57) (57)
---------
TOTAL 643,513
---------
COMPREHENSIVE INCOME
- -----------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (1,367) (1,367)
NET INCOME 19,008 19,008
---------
TOTAL COMPREHENSIVE INCOME 17,641
--------- --------- --------- --------- ---------
MARCH 31, 2003 $135,660 $245,003 $335,541 $(55,050) $661,154
========= ========= ========= ========= =========
DECEMBER 31, 2003 $135,660 $245,003 $359,907 $(43,910) $696,660
Common Stock Dividends (15,000) (15,000)
Preferred Stock Dividends (57) (57)
---------
TOTAL 681,603
---------
COMPREHENSIVE INCOME
- -----------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges (522) (522)
Minimum Pension Liability 23,066 23,066
NET INCOME 4,730 4,730
---------
TOTAL COMPREHENSIVE INCOME 27,274
--------- --------- --------- --------- ---------
MARCH 31, 2004 $135,660 $245,003 $349,580 $(21,366) $708,877
========= ========= ========= ========= =========
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2004 and December 31, 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ---------------------------------------------------------
Production $1,628,532 $1,622,498
Transmission 616,091 615,158
Distribution 1,087,546 1,078,368
General 427,318 423,427
Construction Work in Progress 52,296 60,009
----------- -----------
TOTAL 3,811,783 3,799,460
Accumulated Depreciation and Amortization 1,641,071 1,617,846
----------- -----------
TOTAL - NET 2,170,712 2,181,614
----------- -----------
OTHER PROPERTY AND INVESTMENTS
- ---------------------------------------------------------
Non-Utility Property, Net 3,808 3,808
Other Investments 4,710 4,710
----------- -----------
TOTAL 8,518 8,518
----------- -----------
CURRENT ASSETS
- ---------------------------------------------------------
Cash and Cash Equivalents 66,199 11,724
Advances to Affiliates - 66,476
Accounts Receivable:
Customers 38,049 41,474
Affiliated Companies 26,695 10,394
Miscellaneous 4,697 4,682
Allowance for Uncollectible Accounts (2,089) (2,093)
Fuel Inventory 58,306 63,881
Materials and Supplies 33,139 33,775
Regulatory Asset for Under-recovered Fuel Costs 8,396 11,394
Risk Management Assets 8,392 19,715
Margin Deposits 4,634 5,123
Prepayments and Other 19,059 19,078
----------- -----------
TOTAL 265,477 285,623
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
- ---------------------------------------------------------
Regulatory Assets:
SFAS 109 Regulatory Asset, Net 4,232 3,235
Unamortized Loss on Required Debt 21,891 19,331
Minimum Pension Liability 35,486 -
Other 14,278 15,859
Long-term Risk Management Assets 5,203 12,178
Deferred Charges 81,428 55,605
----------- -----------
TOTAL 162,518 106,208
----------- -----------
TOTAL ASSETS $2,607,225 $2,581,963
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 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 349,580 359,907
Accumulated Other Comprehensive Income (Loss) (21,366) (43,910)
----------- -----------
Total Common Shareholder's Equity 708,877 696,660
Cumulative Preferred Stock Not Subject to Mandatory Redemption 4,700 4,700
----------- -----------
Total Shareholder's Equity 713,577 701,360
Long-term Debt 710,765 741,594
----------- -----------
TOTAL 1,424,342 1,442,954
----------- -----------
Minority Interest 1,159 1,367
----------- -----------
CURRENT LIABILITIES
- --------------------------------------------------------------
Long-term Debt Due Within One Year 144,609 142,714
Advances from Affiliates 36,268 -
Accounts Payable:
General 30,772 37,646
Affiliated Companies 28,422 35,138
Customer Deposits 26,392 24,260
Taxes Accrued 68,373 28,691
Interest Accrued 14,253 16,852
Risk Management Liabilities 7,186 11,361
Obligations Under Capital Leases 3,299 3,159
Regulatory Liability for Over-recovered Fuel 10,829 4,178
Other 30,098 53,753
----------- -----------
TOTAL 400,501 357,752
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
- --------------------------------------------------------------
Deferred Income Taxes 357,013 349,064
Long-term Risk Management Liabilities 3,199 4,667
Reclamation Reserve 14,534 16,512
Regulatory Liabilities:
Asset Removal Costs 240,044 236,409
Deferred Investment Tax Credits 38,783 39,864
Excess Earnings 2,600 2,600
Other 10,228 18,779
Asset Retirement Obligations 8,628 8,429
Obligations Under Capital Leases 18,318 18,383
Deferred Credits and Other 87,876 85,183
----------- -----------
TOTAL 781,223 779,890
----------- -----------
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $2,607,225 $2,581,963
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(Unaudited)
2004 2003
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------
Net Income $4,730 $19,008
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Depreciation and Amortization 31,285 28,035
Deferred Income Taxes (5,182) (4,034)
Deferred Investment Tax Credits (1,081) (1,081)
Deferred Property Taxes (29,063) (27,945)
Cumulative Effect of Accounting Changes - (8,517)
Mark-to-Market of Risk Management Contracts 11,837 (1,462)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (12,895) (1,288)
Fuel, Materials and Supplies 6,211 2,660
Accounts Payable (13,590) (17,294)
Taxes Accrued 39,682 41,182
Fuel Recovery 9,649 2,729
Change in Other Assets (33,109) 1,461
Change in Other Liabilities 8,706 (9,120)
-------- --------
Net Cash Flows From Operating Activities 17,180 24,334
-------- --------
INVESTING ACTIVITIES
- ------------------------------------------------------
Construction Expenditures (19,664) (25,702)
Proceeds from Sale of Assets and Other - 284
-------- --------
Net Cash Flows Used For Investing Activities (19,664) (25,418)
-------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------
Issuance of Long-term Debt 52,179 -
Retirement of Long-term Debt (82,907) (55,450)
Change in Advances to/from Affiliates, Net 102,744 79,884
Dividends Paid on Common Stock (15,000) (18,199)
Dividends Paid on Cumulative Preferred Stock (57) (57)
-------- --------
Net Cash Flows From Financing Activities 56,959 6,178
-------- --------
Net Increase in Cash and Cash Equivalents 54,475 5,094
Cash and Cash Equivalents at Beginning of Period 11,724 2,069
-------- --------
Cash and Cash Equivalents at End of Period $66,199 $7,163
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $15,964,000 and
$17,963,000 and for income taxes was $(2,228,000) and $(755,000) in 2004 and
2003, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS
The notes to SWEPCo's consolidated financial statements are combined with the
notes to respective 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 RESPECTIVE FINANCIAL STATEMENTS
----------------------------------------
The notes to respective financial statements that follow are a combined
presentation for AEP's subsidiary registrants. 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. Assets Held for Sale TCC
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 APCo, KPCo, OPCo, 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.
March 31, December 31,
Components 2004 2003
----------- ---- ----
(in thousands)
Cash Flow Hedges:
APCo $(4,619) $(1,569)
CSPCo (1,707) 202
I&M (1,871) 222
KPCo (335) 420
OPCo (2,625) (103)
PSO (287) 156
SWEPCo (338) 184
TCC (15,590) (1,828)
TNC (5,211) (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, March 31,
2004 Accretion 2004
---------- --------- ----------
(in millions)
AEGCo (a) $1.1 $- $1.1
APCo (a) 21.7 0.5 22.2
CSPCo (a) 8.7 0.2 8.9
I&M (b) 553.2 9.7 562.9
OPCo (a) 42.7 0.8 43.5
SWEPCo (d) 8.4 0.2 8.6
TCC (c) 218.8 4.0 222.8
(a) Consists of asset retirement obligations related to ash ponds.
(b) Consists of asset retirement obligations related to ash
ponds ($1.1 million at March 31, 2004) and nuclear
decommissioning costs for the Cook Plant ($561.8 million at
March 31, 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.
Accretion expense is included in Other Operation expense in the
respective income statements of the individual subsidiary registrants.
As of March 31, 2004 and December 31 2003, the fair value of assets that
are legally restricted for purposes of settling the nuclear
decommissioning liabilities totaled $897 million ($767 million for I&M
and $130 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.
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. 106-1, Accounting and Disclosure Requirements Related
to the Medicare Prescription Drug Improvement and Modernization Act of 2003
- -----------------------------------------------------------------------------
In accordance with FASB Staff Position No. 106-1, in December 2003,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC elected to defer
accounting for any effects of the prescription drug subsidy under the
Medicare Prescription Drug Improvement and Modernization Act of 2003
(the Act) until the FASB issues authoritative guidance on the accounting
for the federal subsidy. The measurements of the accumulated
postretirement benefit obligation and periodic postretirement benefit
cost included in the financial statements do not reflect any potential
effects of the Act. APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and
TNC cannot determine what impact, if any, new authoritative guidance on
the accounting for the federal subsidy may have on their results of
operations or financial condition.
Future Accounting Changes
The Financial Accounting Standards Board's (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 projects related to accounting for stock
compensation, pension plans, property, plant and equipment, earnings per
share calculations 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 the 2003 Annual Report, rate proceedings in the FERC and
several state jurisdictions are ongoing. The Rate Matters note within
the 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 of July 2000 through December 2001 will be
the final fuel reconciliation for TNC's ERCOT service territory. At
December 31, 2001, the deferred under-recovery balance associated with
TNC's ERCOT service area was $27.5 million including interest. During
the reconciliation period, TNC incurred $293.7 million of eligible fuel
costs serving both ERCOT and SPP retail customers. TNC also requested
authority to surcharge its SPP customers for under-recovered fuel costs
as of the end of the reconciliation period. The under-recovery balance
at December 31, 2001 for TNC's service within SPP was $0.7 million
including interest.
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. The remand issues are
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 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.
On December 3, 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 on January 15, 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 February 2002, TNC received a final order from the PUCT in a previous
fuel reconciliation covering the period July 1997 to June 2000 and
reflected the order in its financial statements. This final order was
appealed to the Travis County District Court. In May 2003, the District
Court upheld the PUCT's final order. That order was appealed to the
Third Court of Appeals. In March 2004, the Third Court of Appeals heard
oral arguments. A decision is pending.
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 of July 1998 through December 2001. At December 31, 2001, the
over-recovery balance for TCC was $63.5 million including interest.
During the reconciliation period, TCC incurred $1.6 billion of eligible
fuel and fuel-related expenses.
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. The over-recovery balance and
the provisions total $163 million including interest at March 31, 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, cash flows and financial condition. 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 SPP.
This reconciliation covers the period of 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 addition, the settlement provides for the deferral as
a regulatory asset of costs of a new lignite mining agreement in excess
of a specified benchmark for lignite at SWEPCo's Dolet Hills Plant. The
settlement provides for recovery of the deferred costs over a period
ending in April 2011 as cost savings are realized under the new mining
agreement. The settlement also will allow future recovery of litigation
costs associated with the termination of a previous lignite mining
agreement if we achieve future cost savings. 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%. On February 9, 2004, eight
intervening parties filed testimony recommending reductions to TCC's
requested $67 million rate increase. The recommendations range from a
decrease in existing rates of approximately $100 million to an increase
in TCC's current rates of approximately $27 million. The PUCT Staff
filed testimony, on February 17, 2004, recommending reductions to TCC's
request of approximately $51 million. TCC's rebuttal testimony was filed
on February 26, 2004. The PUCT held hearings in March 2004 and is
expected to issue a decision in June 2004. Management is unable to
predict the ultimate effect of this proceeding on TCC's rates or its
impact on TCC's 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 indicate 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 would adversely
impact results of operations and cash flows.
PSO Fuel and Purchased Power - Affecting PSO
- --------------------------------------------
PSO had a $44 million under-recovery of fuel costs resulting from a
2002 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 recovery
of the $44 million over an 18-month period. 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 were inconsistent with
the FERC-approved Operating Agreement and System Integration Agreement
and could more than offset the $44 million 2002 allocation. The
intervenor and the OCC Staff also believed trading margins were
allocated incorrectly. Under the intervenor's recalculation of margin
allocation, PSO's amount of recoverable fuel would be decreased
approximately $6.8 million for 2000 and $10.7 million for 2001. OCC
Staff calculates the 2001 amount at $8.8 million. They also recommend
recalculation of fuel for years subsequent to 2001 using the same
methods. Hearings are scheduled to occur in June 2004. 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 Costs - 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 $31 million of RTO formation
and integration costs and related carrying charges through March 31,
2004. Amounts per company are as follows:
Company (in millions)
------- -------------
APCo $8.5
CSPCo 3.6
I&M 6.6
KPCo 2.0
OPCo 9.4
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 August 2003, the Virginia SCC filed a request for rehearing
of the July 2003 order, arguing that FERC's action was an infringement
on state jurisdiction, and that FERC should not have treated Alliance
RTO startup costs in the same manner as PJM integration costs. On
October 22, 2003, FERC denied the rehearing request.
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 the deferred RTO 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 at the time they join PJM.
Presently, retail base rates are frozen or capped and cannot be
increased for retail customers of CSPCo, I&M and OPCo. We intend to file
an application with FERC seeking permission to delay the amortization of
the deferred RTO formation/integration costs until they are recoverable
from all users of the transmission system including retail customers.
The AEP East companies are scheduled to join PJM in October 2004,
although there are pending proceedings at the FERC and in Virginia and
Kentucky 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. 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 deferred RTO
formation/integration costs and project implementation cost
reimbursements, if incurred. If the FERC ultimately decides not to
approve a delay 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. A hearing for this proceeding is scheduled in July
2004.
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 is expected to consider the
agreement in May.
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 deferral of the costs for future recovery.
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 has not issued a final order in this matter.
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 July 17, 2003, I&M filed a fuel adjustment clause application
requesting authorization to implement the fixed fuel adjustment charge
(fixed pursuant to a prior settlement of the Cook Nuclear Plant Outage)
for electric service for the billing months of October 2003 through
February 2004, and for approval of a new fuel cost adjustment credit for
electric service to be applicable during the March 2004 billing month.
The Cook settlement agreement provided for the fixed rate to end in
February 2004. In another agreement in connection with a planned
corporate separation I&M agreed, contingent on implementing the
corporate separation, to a new freeze conditionally beginning March 2004
and continuing through December 2007.
On August 27, 2003, the IURC issued an order approving the requested
fixed fuel adjustment charge for October 2003 through February 2004. The
order further stated that certain parties must negotiate the appropriate
action on fuel after March 1, 2004. Negotiations with the parties to
determine a resolution of 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 following the
resolution of issues in the corporate separation agreement. The IURC
also issued an order that reopens the corporate separation docket to
investigate issues related to the corporate separation agreement.
Michigan 2004 Fuel Recovery Plan - Affecting I&M
- ------------------------------------------------
A Michigan Public Service Commission's (MPSC) December 16, 1999 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. In
accordance with the settlement, PSCR Plan cases were not required to be
filed through the 2003 plan year. 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 of
this case occurred on March 10, 2004 and a MPSC order is expected during
the second half of 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 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 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 for residential and small nonresidential customers and permits a
fixed-rate Competitive Bidding Process for large general service
customers and other customer classes. Customers who do not switch to a
competitive generation provider can choose between the Market Based
Standard Service Offer or the Competitive Bidding Process. Customers who
make no choice will be served pursuant to the Competitive Bidding
Process.
On February 9, 2004, CSPCo and OPCo filed their rate stabilization plan
with the PUCO addressing rates following the end of the MDP, which ends
December 31, 2005. If approved by the PUCO, rates would be established
pursuant to the plan for the period from January 1, 2006 through
December 31, 2008 instead of the rates discussed in the previous
paragraph. The plan is intended to provide rate 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 on June
30, 2004, the fixed increases would be 1.6% for CSPCo and 5.7% for OPCo.
The 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 required expenditures. 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. The February
2004 filing provides for the continued deferrals of customer choice
implementation costs during the rate stabilization plan period. At March
31, 2004, CSPCo has incurred $33 million and deferred $13 million and
OPCo has incurred $36 million and deferred $16 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 provided the framework and timetable
to allow retail electricity competition for all 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. See 2004 true-up proceeding
discussion below.
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 PROCEEDING
- -----------------------------
A 2004 true-up proceeding will determine the amount and recovery of:
o net stranded generation plant costs and generation-related regulatory
assets (stranded costs),
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 TNC's filing in May 2004 and TCC's filing in
September 2004 or 60 days after the completion of the sale of TCC's
generation assets, if later.
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 have elected to use the sale of assets
method to determine the market value of TCC's generation assets for
stranded cost purposes. When completed, the sale of TCC's generation
assets will substantially complete the required separation of generation
assets from transmission and distribution assets. 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. It
is anticipated that any such sale will result in significant stranded
costs for purposes of TCC's 2004 true-up proceeding.
In December 2002, TCC filed a plan of divestiture with the PUCT seeking
approval of a sales process for all of its generation facilities. In
March 2003, the PUCT dismissed TCC's divestiture filing, determining
that it was more appropriate to address allowable valuation methods for
the nuclear asset in a rulemaking proceeding. The PUCT approved a rule,
in May 2003, which allows the market value obtained by selling nuclear
assets to be used in determining stranded costs. Although the PUCT
declined to review TCC's proposed sale of assets process, the PUCT hired
a consultant to advise the PUCT and TCC during the sale of the
generation assets. TCC's sale of its generation assets will be subject
to a review in the 2004 true-up proceeding.
In June 2003, we began actively seeking buyers for 4,497 megawatts of
TCC's generating capacity in Texas. In order to sell these assets, TCC
anticipates retiring first mortgage bonds by making open market
purchases or defeasing the bonds. Bids were received for all of TCC's
generation plants. In January 2004, TCC agreed to sell its 7.8%
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% 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, expiring in May and June 2004, to the
co-owners of Oklaunion and STP, respectively. TCC filed for FERC
approval of the sales of the fossil and hydro plants. TCC will request
approval of the STP sale from the FERC during the second quarter of
2004. TCC received a notice from a co-owner of Oklaunion exercising
their right of first refusal; therefore, SEC approval will be required.
Approval of the sale of STP from the Nuclear Regulatory Commission is
required. The completion of the sales is expected to occur in 2004,
subject to rights of first refusal and the necessary approvals required
for each sale. TCC will file its 2004 true-up proceeding with the PUCT
after the sale of the generation assets.
After the 2004 true-up proceeding, TCC may recover stranded costs and
other true-up amounts through transmission and distribution rates as a
competition transition and may seek to issue securitization revenue
bonds for its stranded costs. The cost of the securitization bonds is
recovered through transmission and distribution rates as a separate
transition charge. TCC recorded an impairment of generation assets of
$938 million in December 2003 as a regulatory asset (see Note 7). The
recovery of the regulatory asset will be subject to review and approval
by the PUCT as a stranded cost in the 2004 true-up proceeding.
Wholesale Capacity Auction True-up
- ----------------------------------
Texas Legislation also requires 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. 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. TNC received a written order on March 1, 2004
that established TNC's unrecovered fuel balance, including interest for
the ERCOT service territory, at $4.6 million. This balance will be
included in TNC's 2004 true-up proceeding. Various parties, including
TNC, requested rehearing of the PUCT's order.
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 February 2004, an ALJ issued
recommendations finding a $205 million over-recovery in this fuel
proceeding. 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. 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 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. At March 31, 2004, the remaining retail clawback
liability was $45.5 million for TCC and $11.8 million for TNC.
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 and other true-up amounts, through non-bypassable competition
transition charge in the regulated T&D rates. TCC may also seek to
securitize certain of the approved stranded plant costs and regulatory
assets that were not previously recovered through the non-bypassable
transition charge. The annual costs of securitization are recovered
through a non-bypassable rate surcharge collected by the T&D utility
over the term of the securitization bonds.
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
regulatory assets, unrecovered fuel balances, 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 specific cost
recovery opportunities during the capped rate period, including two
general rate changes and an opportunity for recovery 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) merger litigation, (4) Texas Commercial
Energy, LLP lawsuit, 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 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 is scheduled for July 2004.
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.
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
the contingent liability 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.
OPERATIONAL
- -----------
Power Generation Facility - Affecting OPCo
- ------------------------------------------
AEP has agreements with Juniper Capital L.P. (Juniper) for Juniper to
develop, construct, own and finance a non-regulated merchant power
generation facility (Facility) near Plaquemine, Louisiana and for
Juniper to lease the Facility to AEP. The Facility is a "qualifying
cogeneration facility" for purposes of PURPA. Commercial operation of
the Facility as required by the agreements between Juniper, AEP and The
Dow Chemical Company (Dow) was achieved on March 18, 2004.
Dow will use a portion of the energy produced by the Facility and sell
the excess energy. OPCo has agreed to purchase up to approximately 800
MW of such excess energy from Dow. 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 which is currently in excess of
market. 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.
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.
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. AEP 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 AEP breaches. If the PPA is deemed
terminated or found to be unenforceable by the court, AEP 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 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.
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 pursing 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 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. Management is unable to predict the outcome of this
lawsuit or its impact on results of operations, cash flows or financial
condition.
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. Management is unable to predict the outcome of this
lawsuit or its impact on results of operations, cash flows or financial
condition.
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 this lawsuit or its impact on results of
operations, cash flows and financial condition.
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.
The case is in the initial pleading stage with our response to the
complaint currently due on May 18, 2004. Although management is unable
to predict the outcome of this case, it is not expected to have a
material effect on results of operations due to a provision recorded in
December 2003.
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 are
responding to that request.
Management cannot predict what, if any further action, any of 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. AEP and two unaffiliated utilities
were required to submit generation market power analyses within sixty
days of the FERC's order. 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.
Management is unable to predict the outcome of these actions by the FERC
or their affect on future results of operations and cash flows.
6. GUARANTEES
----------
There are no liabilities recorded for guarantees entered into prior to
December 31, 2002 by registrant subsidiaries in accordance with FIN 45.
There are certain immaterial liabilities recorded for guarantees entered
into subsequent to December 31, 2002. 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 March 31, 2004, the
maximum future payments of the LOC are $43 million which matures
November 2005. AEP holds all assets of the subsidiary as collateral.
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 obligations under 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 March 31,
2004, the cost to reclaim the mine in 2035 is estimated to be
approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.
On July 1, 2003, SWEPCo consolidated Sabine due to the application of
FIN 46. Upon consolidation, SWEPCo recorded the assets and liabilities
of Sabine ($78 million). Also, after consolidation, SWEPCo currently
records all expenses (depreciation, interest and other operation
expense) of Sabine and eliminates Sabine's revenues against SWEPCo's
fuel expenses. There is no cumulative effect of an accounting change
recorded as a result of the requirement to consolidate, and there is no
change in net income due to the consolidation of Sabine.
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 registrant
subsidiaries entered into sale agreements which included
indemnifications with a maximum exposure that was not significant for
any individual registrant subsidiary. There are no material liabilities
recorded for any indemnifications entered into during 2003. There are no
liabilities recorded for any indemnifications entered prior to December
31, 2002.
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 March 31, 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 $1
CSPCo 1
I&M 2
KPCo 1
OPCo 4
PSO 4
SWEPCo 4
TCC 6
TNC 2
7. ASSETS HELD FOR SALE
--------------------
DISPOSITIONS ANNOUNCED DURING FIRST QUARTER 2004
- ------------------------------------------------
During the first quarter of 2004 we announced the following dispositions
expected to close later this year:
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.
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.
Oklaunion Power Station
-----------------------
In January 2004, TCC signed an agreement to sell its 7.8 percent
share of Oklaunion Power Station for approximately $43 million,
subject to closing adjustments. The planned sale is expected to
close in June 2004, subject to the co-owners' decisions on their
rights of first refusal. TCC has received notice from a co-owner
of their decision to exercise their right of first refusal.
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. TCC
expects the sale to close in the second half of 2004, subject to
the co-owners' decisions on their rights of first refusal. TCC
does not expect the sale of this asset to have a significant
effect on its results of operations.
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 for approximately $430 million, subject to closing
adjustments. TCC expects the sale to close in mid-2004, subject to
various regulatory approvals and clearances.
ASSETS HELD FOR SALE
- --------------------
The assets and liabilities of the TCC plants held for sale at March 31,
2004 and December 31, 2003 are as follows:
March 31, 2004 December 31, 2003
-------------- -----------------
Assets: (in millions)
Current Assets $56 $57
Property, Plant and Equipment,
Net 799 797
Regulatory Assets 48 49
Decommissioning Trusts 130 125
------- -------
Total Assets Held for Sale $1,033 $1,028
======= =======
Liabilities:
Regulatory Liabilities $9 $9
Asset Retirement Obligations 223 219
------- -------
Total Liabilities Held for Sale $232 $228
======= =======
8. BENEFIT PLANS
-------------
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in
AEP sponsored U.S. qualified pension plans and nonqualified pension
plans. A substantial majority of employees are covered by either one
qualified plan or both a qualified and a nonqualified pension plan. In
addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, 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 table provides the components of AEP's net periodic benefit
cost (credit) for the plans for the three months ended March 31, 2004
and 2003:
U.S.
U.S. Other Postretirement
Pension Plans Benefit Plans
--------------------- ------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in millions)
Service Cost $22 $20 $11 $11
Interest Cost 57 58 33 32
Expected Return on Plan Assets (73) (79) (21) (16)
Amortization of Transition
(Asset) Obligation - (2) 7 7
Amortization of Net Actuarial Loss 4 2 12 13
----- ---- ---- ----
Net Periodic Benefit Cost (Credit) $10 $(1) $42 $47
===== ==== ==== ====
The following table provides the net periodic benefit cost (credit) for
the plans by the following AEP registrant subsidiaries for the three
months ended March 31, 2004 and 2003:
U.S. U.S. Other
Pension Plans Postretirement Benefit Plans
---------------- ----------------------------
2004 2003 2004 2003
---- ---- ---- ----
(in thousands)
APCo $322 $(1,301) $7,767 $8,438
CSPCo (404) (1,350) 3,367 3,671
I&M 1,118 (203) 5,227 5,750
KPCo 144 (142) 913 1,010
OPCo (28) (1,656) 6,373 7,036
PSO 713 (74) 2,492 2,471
SWEPCo 914 254 2,492 2,566
TCC 766 (30) 2.997 3,238
TNC 344 151 1,262 1,468
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 issuances and retirements during the
first three months of 2004 were:
Principal Interest
Company Type of Debt Amount Rate Due Date
------- ------------ --------- ------- --------
(in thousands) (%)
Issuances:
----------
SWEPCo Installment Purchase Contracts $53,500 Variable 2019
Principal Interest
Company Type of Debt Amount Rate Due Date
------- ------------ --------- ------- --------
(in thousands) (%)
Retirements:
------------
APCo Installment Purchase Contracts $40,000 5.45 2019
OPCo Installment Purchase Contracts 50,000 6.85 2022
OPCo Senior Unsecured Notes 140,000 7.375 2038
OPCo Notes Payable 1,500 6.27 2009
OPCo Notes Payable 1,463 6.81 2008
SWEPCo First Mortgage Bonds 80,000 6.875 2025
SWEPCo Installment Purchase Contracts 450 6.0 2008
SWEPCo Notes Payable 1,707 4.47 2011
SWEPCo Notes Payable 750 Variable 2008
TCC First Mortgage Bonds 1,055 7.125 2005
TCC Securitization Bonds 28,809 3.54 2005
TNC First Mortgage Bonds 24,036 6.125 2004
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). The
following are the SEC authorized limits for short-term borrowings for
the domestic utility companies as of March 31, 2004:
Authorized
----------
(in millions)
AEP Generating Company $125
AEP Texas Central Company (a) 438
AEP Texas North Company (a) 275
Appalachian Power Company 600
Columbus Southern Power Company (a) 150
Indiana Michigan Power Company 500
Kentucky Power Company 200
Ohio Power Company (a) -
Public Service Company of Oklahoma 300
Southwestern Electric Power Company 350
(a) Short-term borrowing limits for these domestic utility
companies are reduced by long-term debt issued commencing with
the SEC order dated December 18, 2002, which authorized
financing transactions through March 31, 2006.
REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
----------------------------------------------------------
The following is a combined presentation of certain components of the
registrants' 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 has not issued a final order in this matter.
In April 2004, KPCo reached an agreement with interveners to settle the
RTO issues in Kentucky. The KPSC is expected to consider the settlement
agreement in May 2004.
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
quarter of 2004, that should be read in order to gain a full
understanding of the current litigation include disclosure related to
the Texas Commercial Energy, LLP Lawsuit.
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 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.
Management is unable to predict the outcome of this lawsuit or its
impact on results of operations, cash flows or financial condition.
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. Management is unable to predict the outcome of this
lawsuit or its impact on results of operations, cash flows or financial
condition.
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 this lawsuit or its impact on results of
operations, cash flows and financial condition could be material.
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.
The case is in the initial pleading stage with our response to the
complaint currently due on May 18, 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 results of
operations.
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 is
responding to that request.
Management cannot predict whether these governmental agencies will take
further action with respect to these matters.
Environmental Matters
- ---------------------
As discussed in the 2003 Annual Report, there are new 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 and adds
estimates of future capital expenditures for the Clean Water Act rule.
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 and
decommissioning.
Future Reduction Requirements for SO2, NOx, and Mercury
- -------------------------------------------------------
In 1997, the Federal EPA adopted new, more stringent NAAQS for fine
particulate matter and ground-level ozone. The Federal EPA is in the
process of developing final designations for fine particulate matter and
ground-level ozone 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 an interstate air quality rule for
reducing SO2 and NOx emissions across the eastern half of the
United States (29 states and the District of Columbia) to
address attainment of the fine particulate matter and
ground-level ozone NAAQS. 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 have not yet been proposed.
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 January 24, 2004 Interstate Air Quality
Rule (IAQR), described above, the Federal EPA proposed that
participation in the trading program under the IAQR would satisfy any
applicable "Best Available Retrofit" requirements.
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, which standards 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 proposed interstate air quality rule. 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 highly effective in reducing mercury emissions on
certain coal-fired units that burn bituminous coal. The second option
contemplates reducing mercury emissions from 48 million tons to 34
million tons by 2010 and to 15 million 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. Comments on both
the initial proposal and the supplemental notice are due on or before
June 29, 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.
Management is unable to estimate the loss or range of loss related to
the contingent liability 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.
Clean Water Act Regulation
- --------------------------
On February 16, 2004, the Federal EPA signed 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 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. 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. 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. AEP and two unaffiliated utilities
were required to submit generation market power analyses within sixty
days of the FERC's order. 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.
Management is unable to predict the outcome of these actions by the FERC
or their affect on future results of operations and cash flows.
CONTROLS AND PROCEDURES
During the first quarter of 2004, AEP's management, including the principal
executive officer and principal financial officer, evaluated AEP's disclosure
controls and procedures relating to the recording, processing, summarization and
reporting of information in AEP's periodic reports that it files with the SEC.
These disclosure controls and procedures have been designed to ensure that (a)
material information relating to AEP, including its consolidated subsidiaries,
is made known to AEP's management, including these officers, by other employees
of AEP and its subsidiaries, 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. AEP's controls and procedures can only
provide reasonable, not absolute, assurance that the above objectives have been
met.
As of March 31, 2004, these officers concluded that the disclosure controls and
procedures in place provide reasonable assurance that the disclosure controls
and procedures accomplished their objectives. AEP 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 AEP's 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 first quarter of 2004 that have materially affected, or are
reasonably likely to materially affect, AEP's 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 March 31,
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 or Under the Plans
Period Of Shares Purchased (1) Paid per Share Programs Or Programs
------ ----------------------- -------------- ---------------------- -------------------
01/01/04 - 01/31/04 9 $65.00 - $-
02/01/04 - 02/29/04 - - - -
03/01/04 - 03/31/04 50 66.00 - -
---- ------- --- ---
Total 59 $65.85 - $-
==== ======= === ===
(1) OPCo and PSO repurchased an aggregate of 9 shares of its 4.5% cumulative preferred stock and 50 shares of its 5% cumulative
preferred stock, respectively, in privately-negotiated transactions outside of an announced program.
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
March 31, 2004.
Company Reporting Date of Report Item Reported
----------------- -------------- -------------
AEP February 3, 2004 Item 7. Financial Statements and Exhibits
Item 12. Results of Operations and Financial Condition
AEP February 24, 2004 Item 7. Financial Statements and Exhibits
Item 9. Regulation FD Disclosure
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: May 7, 2004