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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