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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 JUNE 30, 2003
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, and Telephone Number Identification No.
- ----------- ----------------------------- ------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
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 73-0410895
(An Oklahoma Corporation)
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455
(A Delaware Corporation)
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.
The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at July 31, 2003 was 395,001,853.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2003
Page
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Glossary of Terms i - iii
Forward-Looking Information iv
Part I. FINANCIAL INFORMATION
Items 1 and 2 Financial Statements and Management's Financial Discussion and Analysis:
American Electric Power Company, Inc. and Subsidiary Companies:
Management's Financial Discussion and Analysis A-1 - A-16
Consolidated Financial Statements A-17 - A-21
Notes to Consolidated Financial Statements A-22 - A-50
AEP Generating Company:
Management's Narrative Financial Discussion and Analysis B-1
Financial Statements B-2 - B-5
AEP Texas Central Company and Subsidiaries:
Management's Financial Discussion and Analysis C-1 - C-6
Consolidated Financial Statements C-7 - C-11
AEP Texas North Company:
Management's Narrative Financial Discussion and Analysis D-1 - D-5
Financial Statements D-6 - D-10
Appalachian Power Company and Subsidiaries:
Management's Financial Discussion and Analysis E-1 - E-6
Consolidated Financial Statements E-7 - E-11
Columbus Southern Power Company and Subsidiaries:
Management's Narrative Financial Discussion and Analysis F-1 - F-6
Consolidated Financial Statements F-7 - F-11
Indiana Michigan Power Company and Subsidiaries:
Management's Financial Discussion and Analysis G-1 - G-7
Consolidated Financial Statements G-8 - G-12
Kentucky Power Company:
Management's Narrative Financial Discussion and Analysis H-1 - H-5
Financial Statements H-6 - H-10
Ohio Power Company:
Management's Financial Discussion and Analysis I-1 - I-6
Financial Statements I-7 - I-11
Public Service Company of Oklahoma and Subsidiary:
Management's Narrative Financial Discussion and Analysis J-1 - J-4
Consolidated Financial Statements J-5 - J-9
Southwestern Electric Power Company and Subsidiaries:
Management's Financial Discussion and Analysis K-1 - K-5
Consolidated Financial Statements K-6 - K-10
Notes to Respective Financial Statements L-1 - L-20
Item 4. Controls and Procedures M-1
Part II. OTHER INFORMATION
Item 1. Legal Proceedings N-1
Item 4. Submission of Matters to a Vote of Security Holders N-2
Item 5. Other Information N-4
Item 6. Exhibits and Reports on Form 8-K N-4
(a) Exhibits:
Exhibit 12
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
(b) Reports on Form 8-K
SIGNATURES O-1
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 the recovery of such costs.
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.
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.
AEPR AEP Resources, Inc.
AEP System or the System The American Electric Power System, an integrated electric utility system, owned and
operated by AEP's electric utility subsidiaries.
AEPSC American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP Power Pool AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the
generation, cost of generation and resultant wholesale system sales of the member
companies.
AEP West companies PSO, SWEPCo, TCC and TNC.
Amos Plant John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission Arkansas Public Service Commission.
Buckeye Buckeye Power, Inc., an unaffiliated corporation.
COLI Corporate owned life insurance program.
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.).
CSW Energy CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States. D.C. Circuit Court The United States Court of Appeals for
the District of Columbia Circuit. DOE United States Department of Energy.
ECOM Excess Cost Over Market.
EITF The Financial Accounting Standards Board's Emerging Issues Task Force.
EITF 02-3 Emerging Issues Task Force Issue No. 02-3: Issues Involved in Accounting for Derivative
Contracts Held For Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities.
ERCOT The Electric Reliability Council of Texas.
FASB Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FIN 45 FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others"
FIN 46 FASB Interpretation No. 46" Consolidation of Variable Interest Entities"
GAAP Generally Accepted Accounting Principles.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR Interchange Cost Reconstruction.
IRS Internal Revenue Service.
IURC Indiana Utility Regulatory Commission.
ISO Independent System Operator.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSC Kentucky Public Service Commission.
KWH Kilowatthour.
LIG Louisiana Intrastate Gas.
LPSC Louisiana Public Service Commission
Michigan Legislation The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
MISO Midwest Independent System Operator (an independent operator of transmission assets in the
Midwest).
MLR Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool AEP System's Money Pool.
MPSC Michigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWH Megawatthour.
NOx Nitrogen oxide.
NOx Rule A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including
seven of the states in which AEP companies operate.
NRC Nuclear Regulatory Commission.
OCC The Corporation Commission of the State of Oklahoma.
Ohio Act The Ohio Electric Restructuring Act of 1999.
Ohio EPA Ohio Environmental Protection Agency.
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.
PUCO The Public Utilities Commission of Ohio.
PUCT The Public Utility Commission of Texas.
PUHCA Public Utility Holding Company Act of 1935, as amended.
PURPA The Public Utility Regulatory Policies Act of 1978.
RCRA Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC.
REP Retail Electric Provider.
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.
---------------------------------------------------------
SFAS 101 Statement of Financial Accounting Standards No. 101,
Accounting for the Discontinuance of Application of Statement 71.
----------------------------------------------------------------
SFAS 133 Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities.
------------------------------------------------------------
SFAS 143 Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Operations.
------------------------------------------
SFAS 149 Statement of Financial Accounting Standards No. 149,
Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
---------------------------------------------------------------------------
SFAS 150 Statement of Financial Accounting Standards No. 150,
Accounting for Certain Financial Instruments with Characteristics of both Liabilities
-------------------------------------------------------------------------------------
and Equity.
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SNF Spent Nuclear Fuel.
SPP Southwest Power Pool.
STP South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
AEP electric utility subsidiary.
STPNOC STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
its joint owners including TCC.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central
Power and Light Company (CPL)].
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 [formerly known as West Texas
Utilities Company (WTU)].
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.
WVPSC Public Service Commission of West Virginia.
WPCo Wheeling Power Company, an AEP electric distribution subsidiary.
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
These reports made by AEP and its registrant subsidiaries contain
forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Although AEP and 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 Abnormal weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity.
o The speed and degree to which competition is introduced to our service
territories.
o The ability to recover stranded costs in connection with
deregulation.
o New legislation and government regulation.
o Oversight and/or investigation of the energy sector or its
participants.
o Our ability to successfully control costs.
o The success of acquiring new business ventures and disposing of
existing investments that no longer match our corporate profile.
o International and country-specific developments affecting foreign
investments including the disposition of any current foreign
investments and potential additional foreign investments.
o The economic climate and growth in our service territory and changes
in market demand and demographic patterns.
o Inflationary trends.
o Electricity and gas market prices.
o Interest rates.
o Liquidity in the banking, capital and wholesale power markets.
o Actions of rating agencies.
o Changes in technology, including the increased use of distributed
generation within our transmission and distribution service territory.
o Other risks and unforeseen events, including wars, the effects of
terrorism, embargoes and other catastrophic events.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
American Electric Power Company's consolidated Net Income (Loss) by operating
segment for the quarter and year-to-date periods ended June 30, 2003 and 2002
were as follows:
Three Months Ended Six Months Ended
2003 2002 2003 2002
---- ---- ---- ----
(in millions)
Utility Operations $222 $228 $750 $ 441
Investments - Gas Operations (24) (32) (61) (80)
Investments - UK Operations 3 (12) (59) 11
Investments - Other (26) (122) (15) (479)
---- ---- ---- -----
Total $175 $ 62 $615 $(107)
==== ==== ==== =====
Our Net Income is discussed below according to the operating segments listed
above. Income Before Discontinued Operations and Cumulative Effect
for the quarter and year-to-date were affected by the weather, weak economy and
the availability of electric generation. Year-to-date Net Income of $615
million or $1.64 per share includes $242 million (net of tax) of Income from
Cumulative Effect of Accounting Changes in the first quarter resulting from
the implementation of SFAS 143 (see Note 4) partially offset by $49 million
(net of tax) of Loss from Cumulative Effect of Accounting Changes in the first
quarter resulting from the implementation of EITF 02-3 (see Note 4) and
discontinued operations of $16 million loss (net of tax) (see Note 11). The
loss of $107 million year-to-date 2002 includes discontinued operations of $74
million loss (net of tax) (see Note 11) and a $350 million (net of tax) charge
discussed below in the Investments - Other segment for the implementation of
SFAS 142 (see Note 4).
Utility Operations
Net Income for Utility Operations, our core business, decreased in the quarter
$6 million and increased year-to-date $309 million due to the fluctuations in
operating income along with the year-to-date adjustment for the cumulative
effect of accounting changes. Year-to-date Net Income of $750 million included
$249 million (net of tax) of Income from Cumulative Effect of Accounting Changes
in the first quarter resulting from the implementation of SFAS 143 (see Note 4)
partially offset by $11 million (net of tax) Loss from Cumulative Effect of
Accounting Changes in the first quarter resulting from the implementation of
EITF 02-3 (see Note 4). Operating income decreased in the second quarter and
increased on a year-to-date basis primarily due to:
o Pre-tax earnings increased $59 million in the quarter and $116 million
year-to-date resulting primarily from the non-cash earnings associated
with the stranded cost recovery in Texas which recognizes 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 the PUCT model. This regulatory asset is
expected to be recovered through the 2004 true-up proceeding
established by deregulation laws in Texas.
o Pre-tax earnings for systems sales, transmission revenue and other
wholesale transactions decreased $7 million in the current quarter as a
result of our exit from trading markets where we do not own assets.
Year-to-date pre-tax earnings increased by $66 million due to favorable
power optimization and higher transmission volumes.
o Retail margins from the regulated integrated utilities reduced
pre-tax earnings by $64 million for the quarter and $61 million
year-to-date due to the combined impact of weather, continued weak
economy and costs associated with the Cook Plant outage.
o The reduced demand in the Ohio Companies attributable to the mild
weather in the quarter and the economic pressures on industrial
customers reduced pre-tax earnings by $15 million. Year-to-date pre-tax
earnings increased $5 million due to the average fuel costs being less
than the set recovery rate in revenues.
o The reduction in pre-tax earnings of $38 million for the quarter and
$83 million year-to-date of Texas supply is due to lower margins
attributable to an outage at the STP nuclear plant and a separate
provision for potential disallowance by the PUCT of certain historical
fuel expenses. The Texas supply represents the gross margin for output
of generating units in the ERCOT region and from "reliability must run"
(RMR) contracts with ERCOT.
o Federal Income Taxes decreased $21 million in the quarter and
increased $19 million year-to-date due to the fluctuation in
pre-tax income and the changes in the effective tax rate.
Investments - Gas Operations
Net Loss for the Gas Operations, which include Louisiana Intrastate Gas and
Houston Pipe Line operations, of $24 million in the quarter and $61 million
year-to-date is due to lower margins resulting from our reduced risk profile
and the year-to-date adjustment for the cumulative effect of accounting
changes. These decreases were partially offset by reduced operating and
interest expenses. Year-to-date Net Loss of $61 million included $23 million
(net of tax) of Loss from Cumulative Effect of Accounting Changes in
the first quarter resulting from the implementation of EITF 02-3 (see Note 4).
We have selected advisors to assist with developing a plan of divestiture of its
Louisiana Intrastate Gas holdings. See "Significant Factors - Possible
Divestitures" for additional information.
Investments- UK Operations
Net Loss for the UK Operations, which include Fiddler's Ferry and Ferrybridge
plants (FFF), decreased in the quarter $15 million and increased year-to-date
$70 million due to the fluctuations in operating income along with the
year-to-date adjustment for the cumulative effect of accounting changes.
Year-to-date Net Loss of $59 million included $15 million (net of tax) of Loss
from Cumulative Effect of Accounting Changes in the first quarter resulting from
the implementation of EITF 02-3 (see Note 4) and a $7 million (net of tax) Loss
from Cumulative Effect of Accounting Changes in the first quarter from the
implementation of SFAS 143 (see Note 4). During the second quarter, our U.K.
operations' improved performance was driven primarily by the results of our coal
and freight procurement group and reduced interest expense, as the debt
associated with the plants was retired in early April. Year-to-date our U.K.
operations posted a loss of $37 million driven by a $40 million loss in the
first quarter, due to the continued deterioration in power markets during that
period, and higher operations and maintenance costs which included severance and
redundancy closure costs of the Nordic trading office. Significant liquidity
issues in the U.K. market and the uncertain environmental regulations are still
concerns, so we expect this market to remain a difficult one for the foreseeable
future.
Investments - Other
Net Loss for Other investments, which consists of investments in independent
power plants, coal mines, river transportation, and communications as well as
the discontinued operations of SEEBOARD, CitiPower, Eastex and Pushan, of $26
million in the current quarter 2003 and $15 million year-to-date reflects
discontinued operations losses of $7 million in the quarter and $16 million
year-to-date. The Loss Before Discontinued Operations and Cumulative Effect of
Accounting Changes decreased $7 million in the quarter and $56 million
year-to-date due to lower international development costs, reduced interest
expense and lower costs to wind down operations. The 2002 Net Loss for Other
investments of $122 million in the quarter and $479 million year-to-date
includes discontinued operations losses of $96 million in the quarter and $74
million year-to-date as well as a $350 million (net of tax) first quarter
cumulative effect adjustment for the implementation of SFAS 142 (see Note 4) .
SFAS 142 required that goodwill and intangible assets with indefinite useful
lives no longer be amortized and be tested annually for impairment. The
implementation of SFAS 142 resulted in a $350 million after tax net transitional
loss in 2002 for the SEEBOARD and CitiPower operations.
We have selected advisors to assist with developing a plan of divestiture of
coal mines and certain independent power plants. See "Significant Factors -
Possible Divestitures" for additional information.
Financial Condition
- -------------------
Credit Ratings
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
Senior Notes issued by AEP
Resources (with support
Agreement from AEP) Baa3 BBB BBB+
During the first quarter of 2003, Moody's Investors Service (Moody's), Standard
& Poors (S&P) and Fitch Rating Service completed their reviews of AEP and our
rated subsidiaries. The reviews resulted in downgrades of debt ratings. The
completion of these reviews was a culmination of ratings action started during
2002.
Liquidity
At June 30, 2003, our liquidity sources totaled $3.9 billion and we had an
available liquidity position of $3.3 billion as illustrated in the table below:
Credit Facilities
(in millions) Maturity
--------
Commercial Paper Backup:
Lines of Credit $ 750 5/04
Lines of Credit 1,000 5/05
Lines of Credit 750 5/06
Euro Revolving Credit
Facilities 345 10/03
------
Total 2,845
Liquidity Reserves 300*
Other Temporary
Investments 722*
------
Total Liquidity Sources 3,867
Less: Commercial Paper
Outstanding 547
------
Total Available Liquidity $3,320
======
* These components comprise the Cash and Cash Equivalents balance on our
Consolidated Balance Sheet at June 30, 2003 less $154 million of operational
cash on hand. We maintain the $300 million cash liquidity reserve fund to
support our marketing operations in the U.S. and keep additional cash on hand as
market conditions change.
In April 2003, our Board of Directors declared a common stock dividend of $0.35
per share for the second quarter of 2003, which is a 42% decrease from the
previous quarter's dividend of $0.60 per share. This reduction will result in
annual cash savings of approximately $395 million.
Cash Flow
Six Months Ended June 30,
2003 2002
--------- ---------
(in millions)
Cash and cash equivalents at beginning of period $1,213 $ 224
------ -------
Net cash from (used for) continuing operations:
Operating activities 798 $ 97
Investing activities (596) (784)
Financing activities (239) 1,038
Effect of exchange rate changes on cash and
cash equivalents - (14)
------ -------
Net increase (decrease) in cash and cash equivalents (37) 337
------ -------
Cash and cash equivalents at end of period $1,176 $ 561
====== =======
Cash from operations and short-term borrowings provide working capital and meet
other short-term cash needs. We generally use short-term borrowings to fund
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. We
operate a money pool and sell accounts receivables to provide liquidity for the
domestic electric subsidiaries. Short-term borrowings are supported by a
bank-sponsored receivables purchase agreement and three revolving credit
agreements.
Operating Activities
Cash flows from operating activities during the first half of 2003 were $798
million. Beginning with Income Before Discontinued Operations and Cumulative
Effect of Accounting Changes of $438 million, we add depreciation and deferred
taxes of $702 million and deduct $108 million of non-cash ECOM, $48 million in
mark-to-market changes and $190 million for working capital changes. The
negative working capital changes includes $90 million paid to Williams companies
in settlement for power and gas transactions, and $46 million in increased fuel
inventories.
Investing Activities
Cash flows used for investing activities during the first half of 2003 were $596
million compared to $784 million during the first half of 2002. The major reason
for the year-over-year variance was a construction expenditures reduction of
$135 million and proceeds of $41 million from the sale of assets in 2003 (see
Note 11).
Total consolidated plant and property additions for the first half 2003 were
$649 million, including continued construction expenditures for emission control
technology at several coal-fired generating plants (see Note 8).
Financing Activities
Cash flows from financing activities in the first half of 2003 decreased by
$1,277 million when compared to the first half of 2002 ($(239) million compared
to $1,038 million during 2003 and 2002, respectively), primarily as the result
of AEP's retirement and restructuring of its short-term and long-term debt
during 2003. During the first half of 2003, AEP was able to retire $4,393
million of debt ($2,675 million short-term and $1,718 million of long-term) and
increase available cash primarily through the issuance of long-term financing
($3,546 million), issuance of common stock ($1,177 million) and the generation
of cash from operating activities.
Financing Activity
Common Stock Offering
On February 27, 2003, we priced our offering of 50 million shares of common
stock at a public offering price of $20.95 per share. We granted the
underwriters an option to purchase an additional 7.5 million shares of common
stock to cover over allotments. The underwriters exercised their over allotment
option to purchase an additional 6 million shares. The net proceeds of
approximately $1.1 billion from the sale of these securities were used to reduce
debt and for other corporate purposes.
Debt
In May 2003, a third party exercised its option to call $250 million of 5.50%
putable callable notes, issued by us in May 2001, for purchase and remarketing.
On May 15, 2003, we issued $300 million of 5.25% senior notes due 2015, a
portion of which was an exchange for the $250 million putable callable notes due
in 2003.
In March 2003, we completed an offering of 5.375% Series C Senior Notes which
have a principal amount of $500 million and a maturity date of March 15, 2010.
The net proceeds of $494 million from the offering were used to repay or redeem
current maturities of long-term debt and for other corporate purposes.
In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013
at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at
a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a
variable rate, $150 million of unsecured senior notes due 2005 at a coupon of
3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and
$275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued
$225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The
proceeds from the bond issuances were used to repay the bank facility due to
mature in April 2003, short-term debt and for other corporate purposes.
Also, see Note 15 for further information on financing activities.
Significant Factors
- -------------------
Possible Divestitures
We have a strong commitment to continually evaluate the need to reallocate
resources to areas that effectively match investments with our business
strategy, provide greater potential for financial returns, and to dispose of
investments that no longer meet these principles.
We are seeking to divest assets that consist of domestic and international
unregulated generation, gas pipelines, a coal business and a communications
business. In June 2003, we began actively seeking buyers for 4,497 megawatts of
unregulated generating capacity in Texas to establish a market price for
calculation of stranded cost (see Note 7). Also in the second quarter 2003, we
hired an advisor to evaluate our coal business which has resulted in receipt of
non-binding bids which are currently being evaluated. In the third quarter of
2003, management hired advisors to review business options regarding various
components of our Gas Operations investment. This review is expected to be
completed before year-end and will include an analysis of alternatives for
packaging the business for sale along with review of our investment in gas
operations for impairment of value, including related goodwill of approximately
$300 million. Management is unable to determine the extent of an impairment, if
any, until such evaluation is complete. Management continues 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. If we choose to
dispose of these assets, we may realize non-recurring losses in the aggregate
that could have a material impact on our results of operations, cash flows and
financial condition.
Corporate Separation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), we have filed with the FERC and SEC seeking approval to
separate our regulated and unregulated operations. With the changes in our
business strategy, in response to energy market and business conditions,
management continues to evaluate corporate separation plans, including
determining whether legal corporate separation is appropriate in jurisdictions
where it is not legally required.
RTO Formation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), 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 the subsidiaries'
transmission systems to RTOs.
In May 2002, we announced an agreement with PJM to pursue terms for
participation in its RTO for AEP East companies with final agreements to be
negotiated. In July 2002, FERC issued an order accepting our decision to
participate in PJM, subject to specified conditions. AEP and other parties
continued to work on the resolution of those conditions.
In December 2002, our subsidiaries, which operate in the states of Indiana,
Kentucky, Ohio and Virginia, filed for state regulatory commission approval of
their plans to transfer functional control of their transmission assets to PJM
based on statutory or regulatory requirements in those states. In July 2003, the
KPSC ruled in part that we had failed to prove the benefit of our PJM RTO
membership to Kentucky retail customers and denied our request for approval of
transfer of functional control to PJM. Management plans to seek a rehearing.
Proceedings in the other states remain pending.
In February 2003, the Virginia Legislature enacted legislation, which the
Governor of Virginia signed, that prohibited the transfer of transmission assets
in its jurisdiction to an RTO, until at least July 2004 and then only with
Virginia SCC approval.
In April 2003, FERC approved our transfer of functional control of the AEP East
companies' transmission system to PJM. FERC also accepted our proposed rates for
joining PJM, but set a number of rate issues for resolution through settlement
proceedings or FERC hearings. Settlement discussions continue on certain rate
matters.
AEP West companies are members of ERCOT or the SPP. In 2002, FERC conditionally
accepted filings related to a proposed consolidation of MISO and the SPP. Our
SPP companies are also regulated by state public utility commissions. The
Louisiana and Arkansas commissions filed responses to the FERC's RTO order
indicating that additional analysis was required. Subsequently, the proposed
SPP/MISO combination was terminated. Regulatory activities concerning various
RTO issues are ongoing in Arkansas and Louisiana.
Management is unable to predict the outcome of these transmission regulatory
actions and proceedings or their impact on the timing and operation of RTOs, our
transmission operations or results of operations and cash flows.
Industry Restructuring
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), restructuring and customer choice are in place in four
of the eleven state retail jurisdictions in which our electric utility companies
operate. Restructuring legislation generally provides for a transition from
cost-based rate regulation of bundled electric service to customer choice and
market pricing for the supply of electricity. The status of our transition
plans, regulatory issues and proceedings and accounting issues in the state
regulatory jurisdictions impacted by restructuring and customer choice is
presented in Note 7.
Nuclear Plant Outages
In April 2003, engineers at STP, during inspections conducted regularly as part
of refueling outages, found wall cracks in two bottom mounted instrument guide
tubes of STP Unit 1. These cracks have been repaired and the unit is expected to
return to service in late summer. Our share of the direct cost of repair was
approximately $6 million through June 30, 2003. STP officials are working
closely with the NRC to safely return the unit to service. We have commitments
to provide power to customers during the outage. Therefore, we will be subject
to fluctuations in the market prices of electricity and purchased replacement
energy could be a significant cost.
In April 2003, both units of Cook Plant were taken offline due to an influx of
fish in the plant's cooling water system which caused a reduction in cooling
water to essential plant equipment. After repair of damage caused by the fish
intrusion, Cook Plant Unit 1 returned to service in May and Unit 2 returned to
service in June following completion of a scheduled refueling outage.
Litigation
Federal EPA Complaint and Notice of Violation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings",AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in
litigation since 1999 regarding generating plant emissions under the Clean Air
Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and
eleven unaffiliated utilities made modifications to generating units at
coal-fired generating plants in violation of the Clean Air Act. Federal EPA
filed complaints against our subsidiaries in U.S. District Court for the
Southern District of Ohio. A separate lawsuit initiated by certain special
interest groups was consolidated with the Federal EPA case. The alleged
modification of the generating units occurred 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 Clear Air Act proceedings and
is 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. In the event 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. See Note
8 for further discussion.
NOx Reductions
Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
under the Clean Air Act requiring substantial reductions in NOx emissions in a
number of eastern states, including certain states in which the AEP System's
generating plants are located. The compliance date for the rules is May 31,
2004.
The Texas Commission on Environmental Quality adopted rules requiring
significant reductions in NOx emissions from utility sources, including SWEPCo
and TCC. The compliance requirements began in May 2003 for TCC and begin in May
2005 for SWEPCo.
We are installing selective catalytic reduction (SCR) technology and non-SCR
technology to reduce NOx emissions on certain units to comply with these rules.
Our estimates indicate that compliance with the rules could result in required
capital expenditures in a range of approximately $1.3 billion to $1.7 billion
for the AEP System of which $976 million has been spent through June 30, 2003.
The actual cost to comply could be significantly different than the estimates
depending upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless any capital or operating costs for additional pollution
control equipment are recovered from customers, they will have an adverse effect
on future results of operations, cash flows and possibly financial condition.
See Note 8 for further discussion.
Enron Bankruptcy
In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of the Enron Corporation and its subsidiaries which is pending in the U.S.
Bankruptcy Court for the Southern District of New York. At the date of Enron's
bankruptcy, AEP and its subsidiaries had open trading contracts and trading
accounts receivables and payables with Enron and various HPL related
contingencies and indemnities including issues related to the underground Bammel
gas storage facility and the cushion gas (or pad gas) required for its normal
operation.
Management believes that our entities have the right to utilize offsetting
receivables and payables and related collateral across various Enron entities by
offsetting trading payables owed to various Enron entities against trading
receivables due to us. Management believes we have legal defenses to any
challenge that may be made to the utilization of such offsets. In this regard,
Enron sent to AEPES a demand for payment of approximately $138 million relating
to AEPES' termination of trading contracts. At this time management is unable to
predict the ultimate resolution of these issues or their impact on results of
operations and cash flows. See Note 8 for further discussion.
Bank of Montreal Claim
In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals
and claimed that we owed approximately $34 million. In April 2003, we filed a
lawsuit against BOM claiming BOM had acted contrary to industry practice in
calculating termination and liquidation amounts and that BOM had acknowledged in
March 2003 that it owed us approximately $68 million. Alternatively, we are
claiming that BOM owes us approximately $45 million. Although management is
unable to predict the outcome of this matter, it is not expected to have a
material impact on results of operations, cash flows or financial condition.
Arbitration of Williams Claim
In 2002, we filed a demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding results from Williams' repudiation
of its obligations to provide physical power deliveries to AEP and Williams'
failure to provide the monetary security required for natural gas deliveries.
AEP and Williams settled the dispute with AEP paying $90 million to Williams in
June 2003. The resolution of this matter had an immaterial impact on results of
operations as we had accrued the amount paid. See Note 8 for further discussion.
Arbitration of PG&E Energy Trading, LLC Claim
In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22
million was owed by AEP in connection with the termination and liquidation of
all trading deals. In February 2003, PGET initiated arbitration proceedings. In
July 2003, AEP and PGET agreed to a settlement with AEP paying approximately $11
million to PGET. The settlement payment did not have a material impact on
results of operations, cash flows or financial condition as the payment
approximated our recorded liability.
Energy Market Investigations
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), 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, the U.S. Department of
Justice and the California attorney general during 2002. Management responded to
the inquires and provided the requested information and has continued to respond
to supplemental data request in 2003.
In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing
investigation of energy trading activities. In August 2002, we had received an
informal data request from the SEC seeking that we voluntarily provide
information. The subpoena sought additional information and is part of the SEC's
formal investigation. We responded to the subpoena and will continue to
cooperate with the SEC.
Management cannot predict what, if any action, any of these governmental
agencies may take with respect to these matters.
Shareholders' Litigation
In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against us, certain
executives, members of the Board of Directors and certain investment banking
firms. These cases are in the initial pleading stage. We intend to vigorously
defend against these actions. See Note 8 for further discussion.
California Lawsuit
In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. We intend to vigorously
defend against this action. See Note 8 for further discussion.
Snohomish Settlement
In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract and paid $59 million to us. As a result of the contract
termination, we reversed $69 million of unrealized mark-to-market gains
previously recorded, resulting in a $10 million pre-tax loss.
Other Litigation
We continue to be involved in certain other legal matters discussed in the 2002
Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003).
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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.
New Accounting Pronouncements
See Note 2 for a discussion of significant accounting policies and new
accounting pronouncements.
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.
Policies and procedures have been established to identify, assess, and manage
market risk exposures in our day to day operations. Our risk policies have been
reviewed with the Board of Directors, approved by a Risk Executive Committee and
administered by a Chief Risk Officer. The Risk Executive Committee establishes
risk limits, approves risk policies, assigns responsibilities regarding the
oversight and management of risk and monitors risk levels. This committee
receives daily, weekly, and monthly reports regarding compliance with policies,
limits and procedures. The committee meets monthly and consists of the Chief
Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.
AEP has actively participated in the Committee of Chief Risk Officers (CCRO) to
develop standard disclosures for risk management activities around energy
trading contracts. The CCRO is composed of the chief risk officers of major
electricity and gas companies in the United States. Recently the CCRO adopted
disclosure standards for energy contracts to improve clarity, understanding and
consistency of information reported. Implementation of the new disclosures is
voluntary. AEP supports the work of the CCRO and has embraced the new
disclosures. The following tables provide information on AEP's risk management
activities.
Roll-Forward of Mark-to-Market Risk Management Contract Net Assets
This table provides detail on changes in AEP's mark-to-market (MTM) net asset
or liability balance sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Utility Gas UK
Operations Operations Operations Consolidated
---------- ---------- ---------- ------------
(in millions)
Beginning Balance December 31, 2002 $360 $(155) $ 45 $250
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (139) 63 8 (68)
Fair Value of New Contracts When Entered
Into During the Period (b) - - - -
Net Option Premiums Paid/(Received) (c) 1 53 (7) 47
Change in Fair Value Due to Valuation Methodology
Changes - 1 - 1
Effect of 98-10 Rescission (19) 1 (14) (32)
Changes in Fair Value of Risk Management
Contracts (d) 57 (31) (12) 14
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) 27 - - 27
---- ----- ---- ----
Ending Balance June 30, 2003 $287 $ (68) $ 20 $239
==== ===== ==== ====
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior to
2003.
(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 2003. 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 2003.
(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.
Detail on MTM Risk Management Contract
Net Assets
As of June 30, 2003
Utility Gas UK
Operations Operations Operations Consolidated
---------- ---------- ---------- ------------
(in millions)
Current Assets $ 365 $ 451 $ 166 $ 982
Non Current Assets 418 316 91 825
----- ----- ----- -------
Total MTM Energy Assets $ 783 $ 767 $ 257 $ 1,807
----- ----- ----- -------
Current Liabilities $(281) $(532) $(156) $ (969)
Non Current Liabilities (215) (303) (81) (599)
----- ----- ----- -------
Total MTM Risk Management Contract Liabilities $(496) $(835) $(237) $(1,568)
----- ----- ----- -------
Total MTM Risk Management Contract Net Assets $ 287 $ (68) $ 20 239
===== ===== =====
Net Non-Trading Related Derivative Contracts (114)
Net Fair Value of Risk Management and Derivative
Contracts $ 125
=======
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 AEP's
total MTM asset or liability (external sources or modeled internally)
o The maturity, by year, of AEP's net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
Utility Operations: 2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in millions)
Prices Actively Quoted - Exchange Traded
Contracts $ (4) $ (6) $ (3) $(2) $ - $ - $(15)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 46 59 23 19 6 - 153
Prices Based on Models and Other
Valuation Methods (b) 19 16 14 23 24 53 149
----- ---- ---- --- --- --- ----
Total $ 61 $ 69 $ 34 $40 $30 $53 $287
===== === ==== === === === ====
Gas Operations:
Prices Actively Quoted - Exchange
Traded Contracts (a) $(119) $ 90 $ 9 $ - $ - $ - $(20)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) 119 16 - - - - 135
Prices Based on Models and Other
Valuation Methods (b) (144) (32) (12) 5 8 (8) (183)
----- ---- ---- --- --- --- -----
Total $(144) $ 74 $ (3) $ 5 $ 8 $(8) $ (68)
===== ==== ==== === === === =====
UK Operations:
Prices Actively Quoted - Exchange Traded
Contracts (a) $ - $ - $ - $ - $ - $ - $ -
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 14 6 8 (3) - - 25
Prices Based on Models and Other
Valuation Methods (b) (2) - (5) - 2 - (5)
----- ---- ---- --- --- --- ----
Total $ 12 $ 6 $ 3 $(3) $ 2 $ - $ 20
===== ==== ==== === === === ====
Consolidated:
Prices Actively Quoted - Exchange Traded
Contracts $(123) $ 84 $ 6 $(2) $ - $ - $(35)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) 179 81 31 16 6 - 313
Prices Based on Models and Other
Valuation Methods (b) (127) (16) (3) 28 34 45 (39)
----- ---- ---- --- --- --- ----
Total $ (71) $149 $ 34 $42 $40 $45 $239
===== ==== ==== === === === ====
(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.
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 of the liquid portion
of each energy market.
Maximum Tenor of the Liquid Portion of Risk Management Contracts
As of June 30, 2003
Domestic Tenor
-------- (in months)
Natural Gas Forward Purchases and Sales
NYMEX Henry Hub Gas 66
Gas East - Northeast, Mid-continent
Gulf Coast, Texas 12
Gas West - Permian Basin, San Juan,
Rocky Mtns, Kern, Cdn Border(Sumas),
Malin, PGE Citygate, AECO 12
Power (Peak) Forward Purchases and Sales
Power East - Cinergy 42
Power East - PJM 42
Power East - NYPP 30
Power East - NEPOOL 18
Power East - ERCOT 18
Power East - TVA 0
Power East - Com Ed 18
Power East - Entergy 18
Power West - PV, NP15,SP15,MidC,Mead 54
Peak Power Volatility
(Options) Cinergy 18
OffPeak Power Volatility All Regions 0
Natural Gas
Liquids 11
WTI Crude 48
Emissions 30
Coal 30
International
Power United Kingdom 36
Coal Forward Purchases and Sales United Kingdom 15
Financial Transactions (Swaps) Europe 33
Cash Flow Hedges Included in Accumulated Other Comprehensive Income on the
Balance Sheet
AEP employs 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. AEP does not hedge all interest rate risk.
AEP employs 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. AEP does not hedge all
foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges AEP has in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in Accumulated Other Comprehensive Income (AOCI), the
table does not provide an all-encompassing picture of AEP's hedging activity).
The table further indicates what portions of these hedges are expected to be
reclassified into the income statement in the next 12 months. The table also
includes a roll-forward of the AOCI balance sheet account, providing insight
into the drivers of the changes (new hedges placed during the period, changes
in value of existing hedges and roll off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Cash Flow Hedges included in Accumulated Other Comprehensive Income
On the Balance Sheet as of June 30, 2003
Accumulated Other Portion Expected
Comprehensive to Be Reclassified
Income to Earnings During
(Loss) After Tax(a) Next 12 Months (b)
------------------ ------------------
(in millions)
Power $ (92) $(44)
Foreign Currency (10) (8)
Interest Rate (14) (5)
----- ----
Consolidated $(116) $(57)
===== ====
Total Other Comprehensive Income Activity
Six Months Ended June 30, 2003
Foreign AEP
Power Currency Interest Rate Consolidated
----- -------- ------------- ------------
(in millions)
Accumulated OCI, December 31, 2002 $ (3) $(1) $(12) $ (16)
----------------------------------
Changes in Fair Value (c) (89) (9) (3) (101)
Reclassifications from OCI to Net
Income (d) - - 1 1
---- ---- ---- -----
Accumulated OCI Derivative Loss June 30, 2003 $(92) $(10) $(14) $(116)
==== ==== ==== =====
(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 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.
(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
AEP limits credit risk by assessing creditworthiness of potential counterparties
before entering into transactions with them and continuing to evaluate their
creditworthiness after transactions have been initiated. Only after an entity
has met AEP's internal credit rating criteria will we extend unsecured credit.
AEP uses 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. AEP's independent analysis, in conjunction with the rating
agencies information, is used to determine appropriate risk parameters. AEP also
requires cash deposits, letters of credit and parental/affiliate guarantees as
security from counterparties depending upon credit quality in our normal course
of business.
AEP has risk management contracts with numerous counterparties. Since AEP's open
risk management contracts are valued based on changes in market prices of the
related commodities, AEP's exposures change daily. AEP believes that credit and
market exposures with any one counterparty is not material to AEP's financial
condition at June 30, 2003. At June 30, 2003 AEP's credit exposure net of credit
collateral to sub investment grade counterparties was approximately 10%,
expressed in terms of net MTM assets and net receivables. Net MTM assets
represents the aggregate difference between the forward market price for the
remaining term of the contract and the contractual price per counterparty. As of
June 30, 2003 the following table approximates counterparty credit quality and
exposure for AEP based on netting across AEP entities, 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)
Investment Grade $1,112 $143 $ 969 1 $131
Split Rating 37 - 37 1 36
Non-Investment Grade 191 122 69 3 33
No External Ratings:
Internal Investment
Grade 322 3 319 2 126
Internal Non-Investment
Grade 143 58 85 1 13
------ ---- ------ ----
Total $1,805 $326 $1,479 $339
====== ==== ====== ====
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
Generation Plant Hedging Information
This table provides information on operating measures regarding the proportion
of output of AEP's generation facilities (based on economic availability
projections) economically hedged. This information is forward-looking and
provided on a prospective basis through December 31, 2005. Please note that this
table is point-in time estimates, subject to changes in market conditions and
AEP decisions on how to manage operations and risk.
Generation Plant Hedging Information
Estimated Next Three Years
As of June 30, 2003
2003 2004 2005
---- ---- ----
Estimated Plant Output Hedged (a) 94% 90% 83%
(a) Estimated Plant Output Hedged - Represents the portion of megawatt-hours of
future generation/production for which AEP has sales commitments to customers.
VaR Associated with Energy Trading Contracts
AEP uses a risk measurement model which calculates Value at Risk (VaR) to
measure AEP's commodity price risk in the Energy Trading portfolio. The VaR is
based on the variance - covariance method using historical prices to estimate
volatilities and correlations and assumes 95% confidence level, a one-day
holding period and a one-tailed distribution. Based on this VaR analysis, at
June 30, 2003 a near term typical change in commodity prices is not expected to
have a material effect on AEP's 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
---------
June 30, December 31,
2003 2002
(in millions) (in millions)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$5 $19 $ 7 $5 $5 $24 $12 $4
The High VaR for 2003 occurred in late February 2003 during a period when
natural gas and power prices experienced high levels and extreme volatility.
Within a few days the VaR returned to levels more representative of the average
VaR for the year.
The AEP VaR model results are adjusted using standard statistical treatments to
calculate the CCRO VaR reporting metrics listed below. The adjustments are made
to take the AEP model results from a one-day 95% confidence level to a ten-day
99% confidence level. The AEP VaR model's performance has not been evaluated
for its accuracy at calculating VaR using the CCRO VaR Metrics assumptions.
CCRO VaR Metrics
Average for
End of Year-to-Date High for Low for
June 30, 2003 2003 Year-to-Date 2003 Year-to-Date 2003
-------------- ----------- ------------------ -----------------
(in millions)
95% Confidence Level, Ten-Day
Holding Period, Two-Tailed $20 $27 $71 $17
99% Confidence Level, One-Day
Holding Period, Two-Tailed $ 8 $11 $30 $ 7
AEP utilizes 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, a one year holding period and a one-tailed distribution. The
volatilities and correlations were based on three years of daily prices. The
risk of potential loss in fair value attributable to AEP's exposure to interest
rates, primarily related to long-term debt with fixed interest rates, was $1,217
million at June 30, 2003 and $527 million at December 31, 2002. AEP would not
expect to liquidate its entire debt portfolio in a one year holding period,
therefore a near term change in interest rates should not materially affect
results of operations or consolidated financial position.
AEP is 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 settlement agreements in Michigan
and West Virginia or capped in Indiana. To the extent the fuel supply of the
generating units in these states is not under fixed price long-term contracts
AEP is subject to market price risk. AEP continues to be protected against
market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana,
Kentucky, Virginia and the SPP area of Texas.
AEP employs 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. AEP engages in risk management of
electricity, gas and to a lesser degree other commodities, principally coal
and freight. As a result, AEP is subject to price risk. The amount of risk
taken is controlled by risk management operations and AEP's Chief Risk
Officer and his staff. When the risk from energy trading activities exceeds
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
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
2003 2002 2003 2002
---- ---- ---- ----
REVENUES:
Utility Operations $2,628 $2,660 $5,401 $4,918
Gas Operations 829 670 1,931 1,103
U.K. Operations and Other 212 251 417 552
------ ------ ------ ------
TOTAL REVENUES 3,669 3,581 7,749 6,573
------ ------ ------ ------
EXPENSES:
Fuel for Electric Generation 850 631 1,510 1,252
Purchased Electricity for Resale 215 78 420 107
Purchased Gas for Resale 708 712 1,857 1,066
Maintenance and Other Operation 981 1,199 1,944 2,205
Depreciation and Amortization 336 351 651 683
Taxes Other Than Income Taxes 157 183 345 374
------ ------ ------ ------
TOTAL EXPENSES 3,247 3,154 6,727 5,687
------ ------ ------ ------
OPERATING INCOME 422 427 1,022 886
OTHER INCOME 86 49 204 61
OTHER EXPENSE 57 6 102 26
LESS:INTEREST 198 196 403 391
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 3 3 6 5
MINORITY INTEREST IN FINANCE SUBSIDIARY 8 9 17 18
------ ------ ------ ------
INCOME BEFORE INCOME TAXES 242 262 698 507
INCOME TAXES 60 104 260 190
------ ------ ------ ------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT 182 158 438 317
Discontinued Operations (net of tax) (7) (96) (16) (74)
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX):
Goodwill and Other Intangible Assets - - - (350)
Accounting for Risk Management Contracts - - (49) -
Asset Retirement Obligation - - 242 -
------ ------ ------ ------
NET INCOME (LOSS) $ 175 $ 62 $ 615 $ (107)
====== ====== ====== ======
AVERAGE NUMBER OF SHARES OUTSTANDING 395 326 376 324
=== === === ===
EARNINGS (LOSS) PER SHARE:
Income Before Discontinued Operations And
Cumulative Effect of Accounting Changes $ 0.46 $ 0.48 $ 1.17 $ 0.98
Discontinued Operations (0.02) (0.29) (0.04) (0.23)
Cumulative Effect of Accounting Changes - - 0.51 (1.08)
------ ------ ------ ------
EARNINGS (LOSS) PER SHARE (BASIC
AND DILUTIVE) $ 0.44 $ 0.19 $ 1.64 $(0.33)
====== ====== ====== ======
CASH DIVIDENDS PAID PER SHARE $ 0.35 $ 0.60 $ 0.95 $ 1.20
====== ====== ====== ======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in millions)
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents $ 1,176 $ 1,213
Accounts Receivable (net) 1,685 1,740
Fuel, Materials and Supplies 1,178 1,166
Risk Management Assets 1,010 1,012
Other 883 935
------- -------
TOTAL CURRENT ASSETS 5,932 6,066
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 17,575 17,031
Transmission 5,962 5,882
Distribution 9,709 9,573
Other (including gas, coal mining and
nuclear fuel) 3,926 3,965
Construction Work in Progress 1,272 1,406
------- -------
Total Property, Plant and Equipment 38,444 37,857
Accumulated Depreciation and Amortization 16,031 16,173
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 22,413 21,684
------- -------
REGULATORY ASSETS 2,669 2,688
------- -------
SECURITIZED TRANSITION ASSETS 716 735
------- -------
INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 283
------- -------
GOODWILL 396 396
------- -------
ASSETS HELD FOR SALE 219 292
------- -------
LONG-TERM RISK MANAGEMENT ASSETS 836 819
------- -------
OTHER ASSETS 1,895 1,783
------- -------
TOTAL ASSETS $35,359 $34,746
======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 1,860 $ 2,030
Short-term Debt 567 3,164
Long-term Debt Due Within One Year 1,020 1,633
Risk Management Liabilities 1,055 1,113
Other 1,739 1,802
------- -------
TOTAL CURRENT LIABILITIES 6,241 9,742
------- -------
LONG-TERM DEBT 10,934 8,487
------- -------
EQUITY UNIT SENIOR NOTES 376 376
------- -------
LONG-TERM RISK MANAGEMENT LIABILITIES 666 481
------- -------
DEFERRED INCOME TAXES 4,068 3,916
------- -------
DEFERRED INVESTMENT TAX CREDITS 440 455
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 866 770
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 180 185
------- -------
LIABILITIES HELD FOR SALE 103 142
------- -------
OTHER NONCURRENT LIABILITIES 2,074 1,903
------- -------
COMMITMENTS AND CONTINGENCIES (Note 8)
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF
SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
SUBSIDIARIES 321 321
------- -------
MINORITY INTEREST IN FINANCE SUBSIDIARY 533 759
------- -------
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 144 145
------- -------
COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
2003 2002
---- ----
Shares Authorized. . . 600,000,000 600,000,000
Shares Issued. . . . . 404,001,845 347,835,212
(8,999,992 shares were held in treasury at June 30, 2003
and December 31, 2002) 2,626 2,261
Paid-in Capital 4,182 3,413
Accumulated Other Comprehensive Income (Loss) (670) (609)
Retained Earnings 2,275 1,999
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 8,413 7,064
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $35,359 $34,746
======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in millions)
OPERATING ACTIVITIES:
Net Income (Loss) $ 615 $(107)
Plus: Discontinued Operations 16 74
------- ------
Income from Continuing Operations 631 (33)
Adjustments for Noncash Items:
Depreciation and Amortization 651 687
Deferred Income Taxes 51 (106)
Deferred Investment Tax Credits (16) (10)
Cumulative Effect of Accounting Changes (193) 350
Amortization of Deferred Property Taxes - 35
Amortization of Cook Plant Restart Costs 20 20
Mark to Market of Risk Management Contracts (48) 207
Changes in Certain Current Assets and Liabilities:
Accounts Receivable, net 46 (919)
Fuel, Materials and Supplies (46) 250
Accrued Utility Revenues 51 (176)
Prepayments and Other 93 (411)
Accounts Payable (177) 343
Taxes Accrued 36 (14)
Interest Accrued 11 39
Over/Under Fuel Recovery 85 (35)
Change in Other Assets (209) (325)
Change in Other Liabilities (188) 195
------ -----
Net Cash Flows From Operating Activities 798 97
------ -----
INVESTING ACTIVITIES:
Construction Expenditures (649) (784)
Proceeds from Sale of Assets 41 -
Other 12 -
------ -----
Net Cash Flows Used For Investing Activities (596) (784)
------ -----
FINANCING ACTIVITIES:
Issuance of Common Stock 1,177 656
Issuance of Long-term Debt 3,546 1,786
Issuance of Equity Unit Senior Notes - 334
Change in Short-term Debt, net (2,675) (980)
Retirement of Long-term Debt (1,718) (371)
Retirement of Preferred Stock (2) -
Retirement of Minority Interest (225) -
Dividends Paid on Common Stock (342) (387)
------ -----
Net Cash Flows From (Used For) Financing Activities (239) 1,038
------ -----
Effect of Exchange Rate Change on Cash - (14)
------ -----
Net Increase (Decrease) in Cash and Cash Equivalents (37) 337
Cash and Cash Equivalents at Beginning of Period 1,213 224
------ -----
Cash and Cash Equivalents at End of Period $1,176 $ 561
====== =====
Net Increase in Cash and Cash Equivalents from Discontinued Operations $ 11 $ 19
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 8 108
------ -----
Cash and Cash Equivalents from Discontinued Operations - End of Period $ 19 $ 127
====== =====
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $364 million and $335
million and for income taxes was $155 million and $307 million in 2003 and 2002,
respectively. Noncash acquisitions under capital leases were $1 million in 2003
and $2 million in 2002.
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND
COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
(in millions)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------- -----
JANUARY 1, 2002 $2,153 $2,906 $3,296 $ (126) $8,229
Issuance of Common Stock 108 568 676
Common Stock Dividends (387) (387)
Other (61) (61)
------
8,457
------
Comprehensive Income (Loss):
Other Comprehensive Income (Loss), Net of
Taxes:
Foreign Currency Translation Adjustments 73 73
Unrealized Losses on Cash Flow Hedges (39) (39)
Net Loss (107) (107)
------
Total Comprehensive Income (Loss) (73)
------ ------ ------ ------ ------
JUNE 30, 2002 $2,261 $3,413 $2,802 $ (92) $8,384
====== ====== ====== ====== ======
JANUARY 1, 2003 $2,261 $3,413 $1,999 $(609) $7,064
Issuance of Common Stock 365 812 1,177
Common Stock Dividends (342) (342)
Common Stock Expense (35) (35)
Other (8) 3 (5)
------
7,859
------
Comprehensive Income:
Other Comprehensive Income (Loss), Net of
Taxes:
Foreign Currency Translation Adjustments 23 23
Unrealized Gains on Securities 1 1
Unrealized Losses on Cash Flow Hedges (100) (100)
Minimum Pension Liability 15 15
Net Income 615 615
------
Total Comprehensive Income 554
------ ------ ------ ----- ------
JUNE 30, 2003 $2,626 $4,182 $2,275 $(670) $8,413
====== ====== ====== ===== ======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2003
-------------
(UNAUDITED)
1. GENERAL
-------
The accompanying unaudited interim financial statements should be read
in conjunction with the 2002 Annual Report (as updated by the Current
Report on Form 8-K dated May 14, 2003) as incorporated in and filed with
the Form 10-K/A.
Certain prior period financial statement items have been reclassified to
conform to current period presentation. These items include the effects
of discontinued operations, gains and losses associated with derivative
trading contracts presented on a net basis in accordance with EITF 02-3,
and counterparty netting in accordance with FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts" and EITF Topic
D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy
under FASB Interpretation No. 39". Such reclassifications had no effect
on previously reported Net Income. In addition, management determined
that certain amounts were misclassified in AEP's 2002 Consolidated
Statement of Operations resulting from errors in the coding of certain
intercompany transactions and from transactions associated with our UK
operations (see Note 30 in the Current Report on Form 8-K dated May
14, 2003). As a result, Gas Operations revenues decreased by $2 million
and $49 million, UK Operations and Other revenues decreased by $3
million and $13 million, Fuel for Electric Generation decreased by $17
million and $44 million, and Purchased Gas for Resale decreased by $104
million and $162 million for the three and six month periods ended June
30, 2002, respectively. Expenses for Maintenance and Other Operation
increased by $109 million and $130 million and Taxes Other Than Income
Taxes increased by $7 million and $14 million for the three and six
month periods ended June 30, 2002, respectively. These revisions had no
effect on Operating Income or Net Loss.
In the opinion of management, the unaudited interim financial statements
reflect all normal recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for
interim periods.
2. SIGNIFICANT ACCOUNTING POLICIES AND NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------------------------------------------
Accumulated Other Comprehensive Income
Approximately $57 million of net losses from cash flow hedges in
Accumulated Other Comprehensive Income (Loss) at June 30, 2003 are
expected to be reclassified to net income in the next twelve months as
the items being hedged settle. The actual amounts reclassified from
Accumulated Other Comprehensive Income to Net Income can differ as a
result of market price changes. The maximum term for which the exposure
to the variability of future cash flows is being hedged is approximately
seven years.
SFAS 143 "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. SFAS 143 requires that a cumulative
effect of change in accounting principle be recognized for the
cumulative accretion and accumulated depreciation that would have been
recognized had SFAS 143 been applied to existing legal obligations for
asset retirements. In addition, the cumulative effect of change in
accounting principle is favorably affected by the reversal of
accumulated removal cost that had previously been recorded for
generation that does not qualify as a legal obligation which was
collected in depreciation rates by certain formerly regulated
subsidiaries.
We completed a review of our asset retirement obligations and concluded
that at present, we have related legal liabilities for nuclear
decommissioning costs for our Cook Plant and our partial ownership in
the South Texas Project, as well as liabilities for the retirement of
certain ash ponds, wind farms, the U.K. Plants, and certain coal mining
facilities. Since we presently recover our nuclear decommissioning costs
in our regulated cash flow and thus had existing balances recorded for
such nuclear retirement obligations, we recognized the cumulative
difference in the amount already provided through rates versus the new
methodology of SFAS 143, as a regulatory asset or liability. Similarly,
a regulatory asset was recorded for the cumulative effect of certain
retirement costs for ash ponds related to our regulated operations. In
the first quarter of 2003, we recorded an unfavorable cumulative effect
of $45.4 million after tax for our non-regulated operations ($38.0
million related to Ash Ponds in the Utility Operations segment, $7.2
million related to U.K. Plants in the Investments - UK Operations
segment and $0.2 million for Wind Mills in the Investments - Other
segment).
Certain of our operating companies have recorded in Accumulated
Depreciation and Amortization, removal costs collected from ratepayers
for certain assets that do not have associated legal asset retirement
obligations. To the extent that such operating companies have now been
deregulated, in the first quarter 2003, we reversed the balance of such
removal costs, totaling $287.2 million after tax, from accumulated
depreciation which resulted in a net favorable cumulative effect in the
first quarter of 2003. However, we did not adjust the balance of such
removal costs for our regulated operations, and in accordance with the
present method of recovery, will continue to record such amounts through
depreciation expense and accumulated depreciation. We estimate that we
have approximately $1.2 billion of such regulatory liabilities recorded
in Accumulated Depreciation and Amortization as of both June 30, 2003
and December 31, 2002.
The net favorable cumulative effect of the change in accounting
principle for the six months ended June 30, 2003 consists of the
following:
Pre-tax After-tax
Income (Loss) Income (Loss)
------------ ------------
(in millions)
Ash Ponds $(62.8) $(38.0)
U.K. Plants, Wind Mills and
Coal Operations (11.3) (7.4)
Reversal of Cost of Removal 472.6 287.2
------ ------
Total $398.5 $241.8
====== ======
We have identified, but not recognized, asset retirement obligation
liabilities related to electric transmission and distribution and gas
pipeline assets, as a result of certain easements on property on which
we have assets. Generally, such easements are perpetual and require only
the retirement and removal of our assets upon the cessation of the
property's use. The retirement obligation is not estimable for such
easements since we plan to use our facilities indefinitely. The
retirement obligation would only be recognized if and when we abandon or
cease the use of specific easements.
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, 2003 $718.3 $69.8 $37.2 $825.3
Accretion expense 25.8 2.7 1.0 29.5
Liabilities incurred - - 0.2 0.2
Foreign currency
Translation - - 3.2 3.2
------ ----- ----- ------
Asset Retirement Obligation
Liability at June 30, 2003 $744.1 $72.5 $41.6 $858.2
====== ===== ===== ======
Accretion expense is included in Maintenance and Other Operation in our
accompanying Consolidated Statements of Operations.
As of June 30, 2003 and December 31, 2002, the fair value of assets that
are legally restricted for purposes of settling the nuclear
decommissioning liabilities totaled $778 million and $716 million,
respectively, recorded in Other Assets on our Consolidated Balance
Sheets.
Pro forma net income and earnings per share have not been presented for
the quarter ended June 30, 2002 or the years ended December 31, 2002,
2001 and 2000 because the pro forma application of SFAS 143 would result
in pro forma net income and earnings per share not materially different
from the actual amounts reported for those periods.
Rescission of EITF 98-10
In October 2002, the Emerging Issues Task Force of the FASB reached a
final consensus on Issue No. 02-3. See New Accounting Pronouncements in
Note 1 of the 2002 Annual Report (as updated by the Current Report on
Form 8-K dated May 14, 2003) for further information.
SFAS 149 "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
On April 30, 2003, the FASB issued Statement No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" (SFAS
149). SFAS 149 amends SFAS 133 for certain decisions made by the FASB as
part of the Derivative Implementation Group process and to incorporate
clarifications of the definition of a derivative and which contracts
qualify as "normal purchase/normal sale." SFAS 149 also amends certain
other existing pronouncements. Except for certain provisions of SFAS 149
discussed below, SFAS 149 is effective for contracts entered into or
modified after June 30, 2003, and for hedging relationships designated
after June 30, 2003. The provisions of SFAS 149 relating to decisions
cleared by the FASB as part of the Derivative Implementation Group
process shall continue to be applied in accordance with their respective
effective dates. In addition, certain paragraphs of SFAS 149, which
relate to forward purchases and sales of when-issued securities or other
securities that do not yet exist, shall be applied to both existing
contracts and new contracts entered into after June 30, 2003. We are
currently assessing the impact of the adoption of SFAS 149.
SFAS 150 "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
SFAS 150 was effective for us on July 1, 2003. SFAS 150 is the result of
the first phase of the FASB's project to eliminate from the balance
sheet the "mezzanine" presentation of items with characteristics of both
liabilities and equity, so that no such items will be presented between
liabilities and equity.
SFAS 150 requires that the following three types of freestanding
financial instruments be reported as liabilities: (1) mandatorily
redeemable shares, (2) instruments other than shares that could require
the issuer to buy back some of its shares in exchange for cash or other
assets and (3) obligations that can be settled with shares, the monetary
value of which is either (a) fixed, (b) tied to the value of a variable
other than the issuer's shares, or (c) varies inversely with the value
of the issuer's shares. Measurement of these liabilities generally is to
be at fair value, with the payment or accrual of "dividends" and other
amounts to holders reported as interest cost. Upon adoption of the new
statement, any measurement change for these liabilities is to be
reported as the cumulative effect of a change in accounting principle.
We are currently assessing the impact of the adoption of SFAS 150.
Beginning with our third quarter 2003 financial statements, $321 million
of certain subsidiary obligated, mandatorily redeemable, preferred
securities of subsidiary trusts holding solely junior subordinated
debentures of such subsidiaries, $83 million of mandatorily redeemable
cumulative preferred stock of subsidiaries, and $376 million of equity
unit senior notes, all of which are currently given mezzanine
presentation, are expected to be reclassified as liabilities on our
balance sheet. We are, however, still assessing the ultimate impact of
SFAS 150.
Future Accounting Changes
FASB's standard-setting process is ongoing. 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.
3. STOCK-BASED COMPENSATION PLANS
------------------------------
We have two stock-based employee compensation plans with outstanding
stock options. We account for these plans under the recognition and
measurement principles of APB Opinion No. 25, Accounting for Stock
Issued to Employees (APB 25) and related Interpretations. No stock-based
employee compensation expense is reflected in our earnings, as all
options granted under these plans had exercise prices equal to or above
the market value of the underlying common stock on the date of grant.
We awarded restricted stock units to certain employees in March 2003
which vest in equal one-third increments in January 2004, 2005 and 2006.
At each vesting date, shares will be issued at no cost to the employee.
In accordance with APB 25, the compensation expense will be expensed
over the vesting period of the units. The value of the units was based
on a $21.95 per share value at the grant date. The amount of
compensation expense recognized during the first and second quarters of
2003 in AEP's Consolidated Statements of Operations was not significant.
The following table illustrates the effect on our Net Income (Loss) and
earnings (loss) per share as if we had historically applied the fair
value recognition provisions of FASB Statement No. 123, "Accounting for
Stock-Based Compensation", to stock-based employee compensation awards:
Three Months Ended Six Months Ended
June 30, June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in millions, except per share data)
Net Income (Loss), as reported $ 175 $ 62 $ 615 $ (107)
Add: Stock-based compensation expense included in
reported net income, net of related tax effects - (a) - - (a) -
Deduct: Stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects (2) (3) (3) (5)
----- ------ ----- ------
Pro Forma Net Income (Loss) $ 173 $ 59 $ 612 $ (112)
===== ====== ===== ======
Earnings (Loss) per Share:
Basic - as Reported $0.44 $ 0.19 $1.64 $(0.33)
Basic - Pro Forma 0.44 0.18 1.63 (0.35)
Diluted - as Reported 0.44 0.19 1.64 (0.33)
Diluted - Pro Forma 0.44 0.18 1.63 (0.35)
(a) Compensation expense related to restricted units during the second
quarter of 2003 was not significant.
4. CUMULATIVE EFFECT OF ACCOUNTING CHANGES
---------------------------------------
SFAS 142 requires that goodwill and intangible assets with indefinite
useful lives no longer be amortized, and SFAS 142 now requires that
goodwill and intangible assets be tested annually for impairment.
The implementation of SFAS 142 resulted in a $350 million
after tax net transitional loss in 2002 for the U.K. and Australian
operations and is reported in our Consolidated Statements of Operations
as a cumulative effect of accounting change.
SFAS 143, "Accounting for Asset Retirement Obligations" (see Note 2),
was effective on January 1, 2003. In the first quarter of 2003, we
recorded $242 million in after-tax income related to the recording of
Asset Retirement Obligations in our Consolidated Statements of
Operations as a cumulative effect of accounting change.
EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under
EITF 02-3, mark-to-market accounting is precluded for energy trading
contracts that are not derivatives pursuant to SFAS 133. The consensus
to rescind EITF 98-10 eliminated any basis for recognizing physical
inventories at fair value other than as provided by GAAP. The consensus
to rescind EITF 98-10 is effective for all new contracts entered into
(and physical inventory purchased) after October 25, 2002. The consensus
is effective for fiscal periods beginning after December 15, 2002, and
applies to all energy trading contracts that existed on or before
October 25, 2002 that remain in effect as of the date of implementation,
January 1, 2003. Effective January 2003, nonderivative energy contracts
entered into prior to October 25, 2002 are required to be accounted for
on a settlement basis and inventory is required to be presented at the
lower of cost or market. The effect of implementing this consensus is
reported as a cumulative effect of an accounting change. Such contracts
and inventory are accounted for at fair value through December 31, 2002.
Energy contracts that qualify as derivatives were accounted for at fair
value under SFAS 133. We have recorded a $49 million after tax charge
against net income as Accounting for Risk Management Contracts in our
Consolidated Statements of Operations in Cumulative Effect of Accounting
Changes in the first quarter of 2003 ($11 million in Utility Operations,
$23 million in Investments - Gas Operations and $15 million in
Investments - UK Operations segments). This amount will be realized when
the positions settle.
5. GOODWILL AND OTHER INTANGIBLE ASSETS
------------------------------------
Goodwill
There were no significant changes in the carrying amount of goodwill for
the six months ended June 30, 2003.
Acquired Intangible Assets
The gross carrying amount, accumulated amortization and amortization
life by major asset class are shown in the following table:
June 30, 2003 December 31, 2002
----------------------------- ------------------------------
Gross Gross
Amortization Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------ -------- ------------ -------- ------------
(in millions)
Software and customer list 2 $ - $ - $ 0.5 $0.2
Software acquired 3 0.5 0.2 0.5 -
Patent 5 0.1 - 0.1 -
Easements 10 2.2 0.2 - -
Trade name and
administration of contracts 7 2.4 0.7 2.4 0.6
Purchased technology 10 10.3 1.5 10.3 1.0
Advanced royalties 10 29.4 6.2 29.4 4.7
----- ---- ----- ----
Total $44.9 $8.8 $43.2 $6.5
===== ==== ===== ====
The software and customer list intangible asset was sold as part of the
transfer of the Nordic Trading Business during the second quarter 2003.
Intangible asset amortization expense was $1.4 million and $1.0 million
for the three months ended June 30, 2003 and June 30, 2002. Intangible
asset amortization expense was $2.6 million and $2.0 million for the six
months ended June 30, 2003 and June 30, 2002.
Estimated aggregate amortization expense is $4.7 million in 2004, $4.6
million in 2005 through 2007, $4.4 million in 2008 and $4.2 million in
2009.
Intangible assets subject to amortization are recorded in Other Assets in
the Consolidated Balance Sheets.
6. RATE MATTERS
------------
Fuel in SPP
As discussed in Note 6 of the 2002 Annual Report (as updated by the
Current Report on Form 8-K dated May 14, 2003), in 2001, the PUCT delayed
the start of customer choice in the SPP area of Texas. In May 2003, the
PUCT ordered that competition would not begin in the SPP areas before
January 1, 2007. The PUCT has ruled that TNC fuel factors in the SPP area
will be based upon the price-to-beat fuel factors offered by the retail
electric provider (REP) in the ERCOT portion of TNC's service territory.
TNC filed with the PUCT in 2002 to determine the most appropriate method
to reconcile fuel costs in TNC's SPP area. In April 2003, the PUCT issued
an order adopting the methodology proposed in TNC's filing, with
adjustments, for reconciling fuel costs in its SPP area. The adjustments
removed $3.71 per MWH from reconcilable fuel expense. This adjustment
will reduce revenues received from TNC's SPP customers by approximately
$400,000 annually. These customers are now served by SWEPCo's REP.
TNC Fuel Reconciliation
In June 2002, TNC filed with the PUCT to reconcile fuel costs and 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 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. TNC's SPP customers will continue to be
subject to fuel reconciliations until competition begins in the SPP area.
The under-recovery balance at December 31, 2001 for TNC's service within
SPP was $0.7 million including interest. As noted above, TNC's SPP
customers are now being served by SWEPCo's REP.
In March 2003, the Administrative Law Judges (ALJ) in this proceeding
filed their Proposal for Decision (PFD). The PFD recommends that TNC's
under-recovered retail fuel balance be reduced by approximately $12.5
million. In March 2003, TNC established a reserve of $13 million,
including interest, based on the PFD's recommendations. On April 22,
2003, TNC and intervenors in this proceeding filed exceptions to the PFD.
On May 28, 2003, the PUCT remanded TNC's final fuel reconciliation to the
ALJ to consider several issues. Two of these remand issues could result
in additional disallowances. The issues are the sharing of off-system
sales margins from AEP's trading activities with customers through the
fuel factor 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.
TNC made a filing on July 15, 2003 addressing the remand issues. The PUCT
is proposing that the sharing of off-system sales margins should continue
beyond the termination of the fuel factor. 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. 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 and that after a
more thorough review of the evidence it is only reasonably possible that
the PUCT will determine after the remand proceeding that TNC should share
margins after the end of the Texas fuel factor. Due to a provision
established in the first quarter, the resolution of the fuel factor issue
should have an immaterial impact on results of operations. However, the
decision of the PUCT could result in additional income reductions for
these issues. It is presently expected that the ALJ's PFD and the PUCT's
final decision of these remanded issues will occur in late 2003 or early
2004.
In February 2002, TNC received a final order from the PUCT in a fuel
reconciliation covering the period July 1997 - June 2000 and reflected
the order in its financial statements. This final order had been appealed
to the Travis County District Court. In May 2003, the District Court
upheld the PUCT's final order. The plaintiffs appealed the District
Court's decision to the Third Court of Appeals.
TCC Fuel Reconciliation
In December 2002, TCC filed with the PUCT to reconcile fuel costs and to
defer its over-recovery of fuel for inclusion in the 2004 true-up
proceeding. This reconciliation for the period of July 1998 through
December 2001 will be the final fuel reconciliation. 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. Recommendations from intervening
parties were received in April 2003 and hearings were held in May 2003.
Intervening parties have recommended disallowances totaling $170 million.
In March 2003, the ALJ hearing the TNC final fuel reconciliation,
discussed above, issued a PFD in the TNC proceeding. Various issues
addressed in TNC's proceeding may also be applicable to TCC's proceeding.
Consequently, TCC established a reserve for potential adverse rulings of
$27 million during the first quarter of 2003. Based upon the PUCT's
remand of certain TNC issues, TCC established an additional reserve of $9
million in the second quarter of 2003. An adverse ruling from the PUCT in
excess of the reserves 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 7
"Customer Choice and Industry Restructuring".
SWEPCo Fuel Reconciliation
In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs. This
reconciliation covers the period of January 2000 through December 2002.
At December 31, 2002, SWEPCo's filing detailed a $2.2 million
over-recovery balance including interest. During the reconciliation
period, SWEPCo incurred $434.8 million of eligible fuel expense. An
adverse ruling from the PUCT could have a material impact on future
results of operations, cash flows and financial condition.
ERCOT Price-to-Beat (PTB) Fuel Factor Appeal
Several parties including the Office of Public Utility Counsel (OPC) and
cities served by both TCC and TNC appealed the PUCT's December 2001
orders establishing initial PTB fuel factors for Mutual Energy CPL and
Mutual Energy WTU. On June 25, 2003, the District Court ruled in both
appeals. The Court ruled in the Mutual Energy WTU case that the PUCT
lacked sufficient evidence to include unaccounted for energy in the fuel
factor, erred in including unaccounted for energy in the PTB rate based
on its treatment in other proceedings and that the PUCT had improperly
shifted the burden of proof from the utility to the intervening parties
in not adjusting projected generation requirements for loss of load. The
Court upheld the initial PTB orders on all other issues. In the Mutual
Energy CPL proceeding, the Court ruled that the PUCT should have adjusted
projected generation requirements for the loss of load due to retail
competition. The Court remanded the cases to the PUCT for further
proceedings consistent with its ruling. The amount of unaccounted for
energy built into the PTB fuel factors was approximately $2.7 million for
Mutual Energy WTU. At this time, management is unable to estimate the
potential financial impact related to the loss of load issue. Management
will appeal the District Court decisions and believes, based on the
advice of counsel, that the PUCT's original decision will ultimately be
upheld. If the District Court's decisions are ultimately upheld the PUCT
could reduce the PTB fuel factors charged to retail customers in 2002 and
2003 resulting in an adverse effect on future results of operations and
cash flows.
Unbundled Cost of Service (UCOS) Appeal
TCC placed new transmission and distribution rates into effect as of
January 1, 2002 based upon an order issued by the PUCT resulting from an
UCOS proceeding. TCC requested and received approval of wholesale
transmission rates determined in the UCOS proceeding with the FERC. The
UCOS proceeding set the regulated wires rates to be effective when retail
electric competition began. Regulated delivery charges include the retail
transmission and distribution charge, a system benefit fund fee, a
nuclear decommissioning fund charge, a municipal franchise fee and a
transition charge associated with securitization of regulatory assets.
Certain rulings of the PUCT in the UCOS proceeding, including the initial
determination of stranded costs, the commencement of TCC's excess
earnings refund, regulatory treatment of nuclear insurance and
distribution rates charged municipal customers, were appealed to the
Travis County District Court by TCC and other parties to the proceeding.
The District Court issued a decision on June 16, 2003 upholding the
PUCT's UCOS order with one exception. The Court ruled that the refund of
the 1999 - 2001 excess earnings solely as a credit to non-bypassable
transmission and distribution rates charged to retail electric providers
(REP) discriminates against residential and small commercial customers
and is unlawful. The distribution rate credit began in January 2002. This
decision could potentially affect the PTB rates charged by the AEP REP
(Mutual Energy CPL). Mutual Energy CPL was a subsidiary of AEP until
December 23, 2002 when it was sold to Centrica. Management estimates that
the effect of reducing the PTB rates for the period prior to the sale is
approximately $11 million pre-tax. Management has appealed this decision
and, based on advise of counsel, believes that it will ultimately prevail
on appeal. If the District Court's decision is ultimately upheld on
appeal it could have an adverse effect on future results of operations
and cash flows.
McAllen Rate Review
On June 26, 2003, the City of McAllen requested that TCC provide
justification showing that its transmission and distribution rates should
not be reduced. Other municipalities served by TCC have passed similar
rate review resolutions. In Texas, municipalities have original
jurisdiction over rates of electric utilities within their municipal
limits. Under Texas law, TCC has a minimum of 120 days to provide support
for its rates to the municipalities. TCC has the right to appeal any rate
change by the municipalities to the PUCT. Pursuant to an agreement with
the cities, TCC will file the requested support for its rates with both
the cities and the PUCT on November 3, 2003. Management believes that a
rate reduction is not justified.
Louisiana Fuel Audit
As a result of complaints filed by customers, the LPSC is performing an
audit of SWEPCo's fuel rates. Five SWEPCo customers filed a suit in the
Caddo Parish District Court in January 2003 and filed a complaint with
the LPSC. The customers claim that SWEPCo has over charged them for fuel
costs since 1975. Management believes that SWEPCo's fuel rates prior to
1999 were proper and have been approved by the LPSC. If the LPSC or the
Court rules against SWEPCo, it could have an adverse impact on results of
operations and cash flows.
FERC Wholesale Fuel Complaints
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), certain TNC wholesale customers filed a
complaint with FERC alleging that TNC had overcharged them through the
fuel adjustment clause for certain purchased power costs since 1997.
Negotiations to settle the complaint and update the contracts have
resulted in new contracts. Consequently, an offer of settlement was filed
at FERC in June 2003 regarding the fuel complaint and new contracts.
Management is unable to predict whether FERC will approve this offer of
settlement which is not expected to have a significant impact on TNC's
financial condition. In March 2002, TNC recorded a provision for refund
of $2.2 million before income taxes. TNC anticipates that the provision
for refund will be adequate to cover the financial implications resulting
from these new contracts. Should FERC fail to approve the settlement and
new contracts, the actual refund and final resolution of this matter
could differ materially from the provision and may have a negative impact
on future results of operations, cash flows and financial condition.
Environmental Surcharge Filing
In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff (annual revenue increase of approximately $21 million)
to recover the cost of emissions control equipment being installed at Big
Sandy Plant. See NOx Reductions in Note 8.
In March 2003, the KPSC granted approximately $18 million of the request.
Annual rate relief of $1.7 million was effective in May 2003 and an
additional $16.2 million was effective in July 2003. The recovery of such
amounts is intended to offset KPCo's cost of compliance with the Clean
Air Act.
PSO Rate Review
In February 2003, the Director of the Oklahoma Corporation Commission
(OCC) filed an application requiring PSO to file all documents necessary
for a general rate review before August 1, 2003. The required date to
file the case was subsequently changed to October 31, 2003. Management is
unable to predict the ultimate effect of this review on PSO's rates.
PSO Fuel and Purchased Power
As discussed in Note 6 of the 2002 Annual Report (as updated by the
Current Report on Form 8-K dated May 14, 2003), PSO had a $44 million
under-recovery of fuel costs resulting from a reallocation of purchased
power costs for periods prior to January 1, 2002. On July 23, 2003, PSO
filed with the OCC seeking recovery of the $44 million over an eighteen
month time period. A hearing has been scheduled for October 7, 2003. If
the OCC does not permit recovery, there will be an adverse effect on
results of operations, cash flows and possibly financial condition.
Virginia Fuel Factor Filing
APCo filed with the Virginia SCC to reduce its fuel factor effective
August 1, 2003. The requested fuel rate reduction would be effective for
17 months and is estimated to reduce revenues by $36 million. By order
dated July 23, 2003, the Virginia SCC approved APCo's requested fuel
factor reduction on an interim basis, subject to further investigation.
This fuel factor adjustment will reduce cash flows without impacting
results of operations as any over-recovery of fuel costs would be
deferred as a regulatory liability.
FERC Long-term Contracts
In September 2002, the FERC voted to hold hearings to consider requests
from certain wholesale customers located in Nevada and Washington to
break long-term contracts which they allege are "high-priced". At issue
are long-term contracts entered into during the California energy price
spike in 2000 and 2001. The complaints allege that AEP sold power at
unjust and unreasonable prices. The FERC delayed hearings to allow the
parties to hold settlement discussions. In January 2003, the FERC
settlement judge assigned to the case indicated that the parties'
settlement efforts were not progressing and he recommended that the
complaint be placed back on the schedule for a hearing. In February 2003,
AEP and one of the customers agreed to terminate their contract. The
customer withdrew its FERC complaint and paid $59 million to AEP. As a
result of the contract termination, AEP reversed $69 million of
unrealized mark-to-market gains previously recorded, resulting in a $10
million pre-tax loss.
In a similar complaint, a FERC administrative law judge (ALJ) ruled in
favor of AEP and dismissed, in December 2002, a complaint filed by two
Nevada utilities. In 2000 and 2001, we agreed to sell power to the
utilities for future delivery. In late 2001, the utilities filed
complaints that the prices for power supplied under those contracts
should be lowered because the market for power was allegedly
dysfunctional at the time such contracts were consummated. The ALJ
rejected the utilities' complaint, held that the markets for future
delivery were not dysfunctional, and that the utilities had failed to
demonstrate that the public interest required that changes be made to the
contracts. The ALJ's order is preliminary and is subject to review by the
FERC. At a hearing held in April 2003, the utilities asked FERC to void
the long-term contracts. The FERC will likely rule on the ALJ's order in
2003. Management is unable to predict the outcome of these proceedings or
their impact on future results of operations.
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). On July 2, 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 $22 million of RTO formation
and integration costs and related carrying charges through June 30, 2003.
As a result of the subsequent delay in the integration of AEP's East
transmission system into PJM, FERC declined to rule, at this time, 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 will
apply for permission to transfer the deferred formation/integration costs
to a regulatory asset prior to integration with PJM.
In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO until after June 30, 2004 and only
then with the approval of the Virginia SCC. In the second quarter of
2003, the KPSC denied KPCo's request that they approve our joining PJM
based in part on a lack of evidence that it would benefit Kentucky retail
customers. Management intends to seek a rehearing in Kentucky. Management
does not expect the integration with PJM to occur prior to June 30, 2004.
In its July 2 order, FERC indicated that it would review the deferred
costs for prudency 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's East companies' portion
of the OATT at the time they join PJM. Presently, retail rates are frozen
or capped and cannot be increased for retail customers of CSPCo, I&M and
OPCo. We intend to apply 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. 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. Management intends to seek
recovery of the deferred RTO formation/integration costs. 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.
FERC Order on Regional Through and Out Rates (RTOR)
On July 23, 2003, the FERC issued an order directing PJM and the Midwest
ISO to make compliance filings for their respective Open Access
Transmission Tariffs to eliminate, by November 1, 2003, the Regional
Through and Out Rates (RTOR) on transactions where the energy is
delivered within the Midwest ISO and PJM regions. The elimination of the
RTORs 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 RTORs.
The FERC also found that the through and out 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 Midwest
ISO/PJM regions. FERC has initiated an investigation and hearing in
regard to these rates. We will make a filing with the FERC supporting the
justness and reasonableness of our rates by August 15, 2003. Management
at this time is unable to predict the ultimate outcome of this
investigation, or the impact on our results of operations and cash flows.
7. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
------------------------------------------
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), retail customer choice began in four of
the eleven state retail jurisdictions (Michigan, Ohio, Texas and
Virginia) in which the AEP domestic electric utility companies operate.
The following paragraphs discuss significant events occurring in 2003
related to customer choice and industry restructuring.
Ohio Restructuring
On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy
Users-Ohio and American Municipal Power-Ohio filed a complaint with the
PUCO alleging that CSPCo and OPCo have violated the PUCO's orders
regarding implementation of their transition plan and violated other
applicable law by failing to participate in an RTO.
The complainants seek, among other relief, an order from the PUCO:
o suspending collection of transition charges by CSPCo and OPCo
until transfer of control of their transmission assets has
occurred
o pricing standard offer electric generation effective
January 1, 2006 at the market price used by CSPCo and OPCo
in their 1999 transition plan filings to estimate
transition costs and
o imposing a $25,000 per company forfeiture for each day AEP
fails to comply with its commitment to transfer control of
transmission assets to an RTO
Due to the FERC's reversal of its previous approval of our RTO filings
and state legislative and regulatory developments, CSPCo and OPCo have
been delayed in the implementation of their RTO participation plans. We
continue to pursue integration of CSPCo, OPCo and other AEP East
companies into PJM. In this regard on December 19, 2002, CSPCo and OPCo
filed an application with the PUCO for approval of the transfer of
functional control over certain of their transmission facilities to PJM.
In February 2003, the PUCO consolidated the June complaint with our
December application. CSPCo's and OPCo's motion to dismiss the complaint
has been denied by the PUCO and the PUCO affirmed that ruling in
rehearing. All further action in the consolidated case has been stayed
"until more clarity is achieved regarding matters pending at the FERC
and elsewhere". Management is unable to predict the timing of the AEP's
East companies' participation in PJM, or the outcome of these
proceedings before the PUCO.
On March 20, 2003, the PUCO commenced a statutorily-required
investigation concerning the desirability, feasibility and timing of
declaring retail ancillary, metering or billing and collection service
supplied to customers within the certified territories of electric
utilities a competitive retail electric service. The PUCO sent out a
list of questions and set June 6, 2003 and July 7, 2003, as the dates
for initial responses and replies, respectively. CSPCo and OPCo filed
comments and responses in compliance with the PUCO's schedule.
Management is unable to predict the timing or the outcome of this
proceeding.
The Ohio Act provides for a Development Period during which retail
customers can choose their electric power suppliers or have the
protection of Default Service at frozen generation rates from the
incumbent utility. The Development Period began on January 1, 2001 and
will terminate no later than December 31, 2005, but the PUCO may
terminate the Development Period 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 Development Period, 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 have the
protection of Default Service which must be offered by the incumbent
utility at market rates. The PUCO has circulated a draft of proposed
rules but has not yet identified the method by which it will determine
market rates for Default Service following the Development Period.
As provided in the stipulation agreement approved by the PUCO, we are
deferring customer choice implementation costs in excess of $40 million.
The agreements provide for the deferral of these costs as a regulatory
asset until the next distribution base rate case. We have deferred $22
million of such costs. Recovery of these regulatory assets will be
subject to PUCO review in our next Ohio distribution rate filings which
will not occur until after 2008 for CSPCo and 2007 for OPCo. Management
believes that the amounts deferred represent prudently incurred customer
choice implementation costs and 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
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), on January 1, 2002, customer choice of
electricity supplier began in the ERCOT area of Texas. Customer choice
has been delayed in other areas of Texas including the SPP area in which
SWEPCo operates. In May 2003, the PUCT approved a stipulation that
delays competition in the SPP area until at least January 1, 2007.
A 2004 true-up proceeding will determine the amount of stranded costs,
final fuel balance, net regulatory assets, certain environmental costs,
accumulated excess earnings, excess of price-to-beat revenues over
market prices subject to certain conditions and limitations (Retail
clawback), a true-up of the power costs used in the PUCT's ECOM model
for 2002 and 2003 to reflect actual market prices determined through
legislatively-mandated capacity auctions (Wholesale capacity auction
true-up) and other restructuring issues.
The Texas Legislation allows for several alternative methods to be used
to value stranded costs in the final 2004 true-up proceeding including
the sale or exchange of generation assets, stock valuation or the use of
an ECOM model. Only TCC has stranded costs under the Texas Legislation.
In late 2002, TCC decided to obtain a market value of generating assets
for purposes of determining stranded costs for the 2004 true-up
proceeding and filed a plan of divestiture with the PUCT seeking
approval of a sales process for all of its generating facilities. Such
sales would quantify the actual stranded costs. The amount of stranded
costs under this market valuation methodology will be the amount by
which net book value of TCC's generating 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. The filing included a request for the PUCT to issue a
declaratory order that TCC's 25.2% ownership interest in its nuclear
plant, STP, can be sold to value stranded costs. Intervenors to this
proceeding, including the PUCT Staff, made filings to dismiss TCC's
filing claiming that the PUCT does not have the authority to issue a
declaratory order. The intervenors also argued that the proper time to
address the sales process is after the plants are sold during the 2004
true-up proceeding. Since the bidding process is not expected to be
completed before mid-2004, TCC requested that the 2004 true-up
proceeding be scheduled after completion of the divestiture of the
generating assets.
In March 2003, the PUCT dismissed TCC's divestiture filing, determining
that it was more appropriate to address the nuclear asset stranded costs
valuation in a rulemaking proceeding. The PUCT approved a rule, in May
2003, that allows the value obtained by selling nuclear assets to be
used in determining stranded costs. Since the PUCT also dismissed the
request to certify the proposed divestiture plan, the divestiture plan
utilized by TCC will still be subject to a review in the 2004 true-up
proceedings. The PUCT adopted a rule regarding the timing of the 2004
true-up proceedings scheduling TNC's filing in May 2004 and TCC's filing
in September 2004.
Texas Legislation also requires that electric utilities and their
affiliated power generation companies (PGC) sell at auction in 2002 and
2003 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 and liquidity. Actual
market power prices received in the state mandated auctions will replace
the PUCT's earlier estimates of those market prices used in the ECOM
model to calculate the wholesale capacity auction true-up adjustment for
TCC for the 2004 true-up proceeding.
The decision to determine stranded costs by selling TCC's generating
plants and the expectation that the sales price would produce a
significant loss/stranded costs instead of using the PUCT's ECOM model
estimates, enabled TCC to record in 2002 a $262 million regulatory asset
and related revenues which represents the quantifiable amount of the
wholesale capacity auction true-up for the year 2002. Through June 30,
2003, TCC recorded an additional $108 million regulatory asset and
related revenues for wholesale capacity auction true-up. Prior to the
decision to pursue a sale of TCC's generating assets, the PUCT's ECOM
estimate prohibited the recognition of the regulatory assets and
revenues as they can not be recovered unless there are stranded costs.
As discussed above, a defined process is required in order to determine
the amount of stranded costs related to generation facilities for the
2004 true-up proceedings.
When the divestiture and the 2004 true-up proceeding are completed, TCC
can securitize stranded costs that are in excess of current securitized
amounts. The annual costs of securitization will be recovered through a
non-bypassable rate surcharge by the regulated transmission and
distribution (T&D) utility over the life of the securitization bonds.
Any stranded costs and other true-up amounts not recovered through the
sale of securitization bonds may be recovered through a separate
non-bypassable competition transition charge to T&D utility customers.
In the event we are unable, after the 2004 true-up proceeding, to
recover all or a portion of our generation-related regulatory assets,
unrecovered fuel balances, stranded costs, other true-up adjustments and
other restructuring related costs, it could have a material adverse
effect on results of operations, cash flows and possibly financial
condition.
Arkansas Restructuring
In February 2003, Arkansas repealed customer choice legislation
originally enacted in 1999. Consequently, SWEPCo's Arkansas operations
reapplied SFAS 71 regulatory accounting which had been discontinued in
1999. The reapplication of SFAS 71 had an insignificant effect on
results of operations for the first six months of 2003. As a result of
reapplying SFAS 71, derivative contract gains/losses for transactions
within AEP's traditional marketing area allocated to Arkansas will not
affect income until settled. That is, such positions will be recorded on
the balance sheet as either a regulatory asset or liability until
realized.
West Virginia Restructuring
APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the
first quarter of 2003 after new developments during the quarter prompted
an analysis of the probability of restructuring becoming effective.
In 2000, the WVPSC issued an order approving an electricity
restructuring plan, which the WV Legislature approved by joint
resolution. The joint resolution provided that the WVPSC could not
implement the plan until the WV legislature made tax law changes
necessary to preserve the revenues of state and local governments.
In the 2001 and 2002 legislative sessions, the WV Legislature failed to
enact the required legislation that would allow the WVPSC to implement
the restructuring plan. Due to this lack of legislative activity, the
WVPSC closed two proceedings related to electricity restructuring during
the summer of 2002.
In the 2003 legislative session, the WV Legislature failed to enact the
required tax legislation. Also, a March 2003 WV Legislative Bill
clarified the jurisdiction of the WVPSC over electric generation
facilities in WV. In March 2003, APCo's outside counsel advised us that
restructuring in WV was no longer probable and confirmed facts relating
to the WVPSC's jurisdiction and rate authority over APCo's WV
generation. APCo has concluded that deregulation of the WV generation
business is no longer probable and operations in WV meet the
requirements to reapply SFAS 71.
The result of reapplying SFAS 71 in WV had an insignificant effect on
results of operations during the first six months of 2003. As a result,
derivative contract gains/losses related to transactions within AEP's
traditional marketing area allocated to WV will not affect income until
settled. That is, such positions will be recorded on the balance sheet
as either a regulatory asset or liability until realized. Positions
outside AEP's traditional marketing area will continue to be
marked-to-market.
8. COMMITMENTS AND CONTINGENCIES
-----------------------------
Power Generation Facility
AEP has agreements with Juniper Capital L.P. (Juniper) under which
Juniper will develop, construct, and finance a power generation facility
(Facility) near Plaquemine, Louisiana and lease the Facility to AEP.
Construction of the Facility was begun by Katco Funding, Limited
Partnership (Katco), an unrelated unconsolidated special purpose entity,
and Katco assigned its interest in the Facility to Juniper in June 2003.
Juniper is a limited partnership, unaffiliated and unconsolidated with
AEP, 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 has arranged to
finance the Facility with debt financing up to $471 million and equity
up to $29 million (approximately 6%) of the Facility's acquisition cost
from investors with no relationship to AEP or any of AEP's subsidiaries.
Juniper will own the Facility and lease it to AEP after construction is
completed. The lease will be treated as an operating lease for financial
accounting purposes. Consequently, the Facility and the related
obligations are not reported on AEP's consolidated balance sheet.
Payments under the operating lease are expected to commence in the first
quarter of 2004. AEP will in turn sublease the Facility to Dow Chemical
Company (DOW). The use of Juniper allows AEP to limit its risk
associated with the Facility once construction has been completed. In
addition, the lease allows AEP to utilize certain tax benefits
associated with the Facility.
AEP is the construction agent for Juniper. Construction is currently
scheduled to be completed by the first quarter of 2004, subject to
unforeseen events beyond AEP's control.
In the event the project is terminated before completion of
construction, AEP has the option to either purchase the Facility for
100% of Juniper's acquisition cost (which, in general, is the
outstanding debt and equity associated with the Facility) or terminate
the project and make a payment to Juniper for 89.9% of project costs.
DOW will use a portion of the energy produced by the Facility and sell
the excess energy. AEP has agreed to purchase approximately 800 MW of
such excess energy from DOW. AEP has a contract to resell that energy to
Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years.
Beginning May 1, 2003, AEP had certain contractual rights and
obligations in connection with providing replacement energy and other
products to TEM. TEM has rejected the replacement energy. On June 27,
2003, AEP and TEM signed a "standstill agreement" whereby negotiations
will occur up to August 25, 2003. During this negotiation period, no
power will be delivered to TEM under the contract, but both parties will
retain all rights as if AEP offered the power and TEM rejected it. If
the project is not completed by April 30, 2004, TEM may claim that it
can terminate the purchase agreement and is owed liquidating damages of
approximately $17.5 million.
The initial term of the operating lease between Juniper and AEP
commences on the commercial operation date (COD) of the Facility and
continues for five years or, if earlier, until June 2009. The lease
contains extension options and if all extension options were exercised,
the total term of the lease would be 30 years. AEP's lease payments to
Juniper during the initial term and each extended term are sufficient
for Juniper to make required debt payments under Juniper's debt
financing associated with the Facility and provide a return on equity to
the investors in Juniper. AEP has the right to purchase the Facility for
the acquisition cost during the last month of the initial term or on any
monthly rent payment date during any extended term. In addition, AEP may
purchase the Facility for the acquisition cost at any time during the
initial term if AEP has arranged a sale of the Facility to an
unaffiliated third party. A purchase of the Facility from Juniper by AEP
would not alter DOW's rights to lease the Facility or AEP's contract to
purchase energy from DOW. At the end of the anticipated 30-year lease
term, AEP may renew the lease at fair market value subject to Juniper's
approval, purchase the Facility at its original construction cost, or
sell the Facility, on behalf of Juniper, to an independent third party.
If the Facility is sold and the proceeds from the sale are insufficient
to pay all of Juniper's acquisition costs, AEP may be required to make a
payment (not to exceed $377 million) to Juniper of the excess of
Juniper's acquisition costs over the proceeds from the sale up to
approximately 75% of the project's cost, provided that AEP would not be
required to make any payment if AEP has made the additional rental
prepayment described below. AEP has guaranteed the obligations of its
subsidiaries to Juniper during the construction and post-construction
periods. Due to FIN 45, at COD, AEP will be required to record the fair
value (approximately $16 million) of this guarantee as a liability with
an offsetting asset.
As of June 30, 2003, Juniper's project costs for the Facility totaled
$441 million, and total costs for the completed Facility are expected to
be approximately $500 million. For the 30-year extended lease term, the
base lease rental is a variable rate obligation indexed to three-month
LIBOR. Consequently as market interest rates increase, the base rental
payments under this operating lease will also increase. Annual payments
of approximately $16 million represent future minimum payments during
the initial term calculated using the indexed LIBOR rate (1.12% at June
30, 2003). An additional rental prepayment (up to $377 million as of
June 30, 2003) may be due on June 30, 2004 unless Juniper has refinanced
its present debt financing on a long-term basis. The Facility is
collateral for the debt obligation of Juniper. Our maximum exposure to
loss as a result of its involvement with Juniper is 100% of Juniper's
acquisition costs during the construction phase and up to $377 million
once the construction is completed. These calculations could change
based on the final amount of total costs or changes in interest rates.
Maximum loss is deemed to be remote due to the collateralization.
As a result of Katco's transfer of its interest in the Facility to
Juniper, we will not consolidate Juniper or any portion of the
Facility in accordance with FIN 46.
Nuclear Plant Outages
In April 2003, engineers at STP, during inspections conducted regularly
as part of refueling outages, found wall cracks in two bottom mounted
instrument guide tubes of STP Unit 1. These cracks have been repaired
and the unit is expected to return to service in late summer. Our share
of the direct cost of repair was approximately $6 million through June
30, 2003. STP officials are working closely with the NRC to safely
return the unit to service. We have commitments to provide power to
customers during the outage. Therefore, we will be subject to
fluctuations in the market prices of electricity and purchased
replacement energy could be a significant cost.
In April 2003, both units of Cook Plant were taken offline due to an
influx of fish in the plant's cooling water system which caused a
reduction in cooling water to essential plant equipment. After repair of
damage caused by the fish intrusion, Cook Plant Unit 1 returned to
service in May and Unit 2 returned to service in June following
completion of a scheduled refueling outage.
Federal EPA Complaint and Notice of Violation
As discussed in Note 9 of the Combined Notes to Financial Statements in
the 2002 Annual Report (as updated by the Current Report on Form 8-K
dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", AEPSC, APCo, CSPCo, I&M, and OPCo have been
involved in litigation regarding generating plant emissions under the
Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo,
I&M, OPCo and eleven unaffiliated utilities modified certain units at
coal-fired generating plants in violation of the Clean Air Act. Federal
EPA filed complaints against our subsidiaries in U.S. District Court for
the Southern District of Ohio. A separate lawsuit initiated by certain
special interest groups was consolidated with the Federal EPA case. The
alleged modification of the generating units occurred over a 20 year
period.
Under the Clean Air Act, 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 Clean Air Act
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.
Management believes its maintenance, repair and replacement activities
were in conformity with the Clean Air Act and intends to vigorously
pursue its defense.
Management is unable to estimate the loss or range of loss related to
the contingent liability for civil penalties under the Clear Air Act
proceedings and 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. In the event 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 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.
NOx Reductions
Federal EPA issued a NOx Rule requiring substantial reductions in NOx
emissions in a number of eastern states, including certain states in
which the AEP System's generating plants are located. The NOx Rule has
been upheld on appeal. The compliance date for the NOx Rule is May 31,
2004.
In 2000, Federal EPA also adopted a revised rule (the Section 126 Rule)
granting petitions filed by certain northeastern states under the Clean
Air Act. The rule imposes emissions reduction requirements comparable to
the NOx Rule beginning May 1, 2003, for most of our coal-fired
generating units. Affected utilities, including certain AEP operating
companies, petitioned the D.C. Circuit Court to review the Section 126
Rule.
After review, the D.C. Circuit Court instructed Federal EPA to justify
the methods it used to allocate allowances and project growth for both
the NOx Rule and the Section 126 Rule. AEP subsidiaries and other
utilities requested that the D.C. Circuit Court vacate the Section 126
Rule or suspend its May 2003 compliance date. In 2001, the D.C. Circuit
Court issued an order tolling the compliance schedule until Federal EPA
responds to the Court's remand. On April 30, 2002, Federal EPA announced
that May 31, 2004 is the compliance date for the Section 126 Rule.
Federal EPA published a notice in the Federal Register on May 1, 2002
advising that no changes in the growth factors used to set the NOx
budgets were warranted. In June 2002, our subsidiaries joined other
utilities and industrial organizations in seeking a review of Federal
EPA's actions in the D.C. Circuit Court. This action is pending.
In 2000, the Texas Commission on Environmental Quality adopted rules
requiring significant reductions in NOx emissions from utility sources,
including TCC and SWEPCo. The compliance requirements began in May 2003
for TCC and begin in May 2005 for SWEPCo.
We are installing a variety of emission control technologies to reduce
NOx emissions to comply with the applicable state and Federal NOx
requirements. This includes selective catalytic reduction (SCR)
technology on certain units and non-SCR technologies on a larger number
of units. During 2001 SCR technology commenced operations on OPCo's
Gavin Plant. Installation of SCR technology on Amos and Mountaineer
plants was completed and commenced operation in May 2002. In May 2003,
SCR technology installed at Big Sandy and Cardinal plants commenced
operation. Construction of SCR technology at certain other AEP
generating units continues. Non-SCR technologies have been installed and
commenced operation on a number of units across the AEP System and
additional units will be equipped with these technologies.
Our NOx compliance plan is a dynamic plan that is continually reviewed
and revised as new information becomes available on the performance of
installed technologies and the cost of planned technologies. Certain
compliance steps may or may not be necessary as a result of this new
information. Consequently, the plan has a range of possible outcomes.
Current estimates indicate that our compliance with the NOx Rule, the
Texas Commission on Environmental Quality rule and the Section 126 Rule
could result in required capital expenditures in the range of $1.3
billion to $1.7 billion, of which $976 million has been spent through
June 30, 2003. Since compliance costs cannot be estimated with
certainty, the actual cost to comply could be significantly different
than the estimates depending upon the compliance alternatives selected
to achieve reductions in NOx emissions. Unless any capital and operating
costs for additional pollution control equipment are recovered from
customers, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition.
Enron Bankruptcy
On October 15, 2002, certain subsidiaries of AEP filed claims against
Enron and its subsidiaries in the bankruptcy proceeding filed by the
Enron entities which are 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, we purchased Houston Pipe Line Company (HPL) from Enron. Various
HPL related contingencies and indemnities remained unsettled at the date
of Enron's bankruptcy. The timing of the resolution of the claims by the
Bankruptcy Court is not certain.
In connection with the 2001 acquisition of HPL, we acquired exclusive
rights to use and operate the underground Bammel gas storage facility
pursuant to an agreement with BAM Lease Company, a now-bankrupt
subsidiary of Enron. This exclusive right to use the referenced facility
is for a term of 30 years, with a renewal right for another 20 years and
includes the use of the Bammel storage facility and the appurtenant
pipelines. We have engaged in preliminary discussions with Enron
concerning the possible purchase of the Bammel storage facility and
related assets, the possible resolution of outstanding issues between
AEP and Enron relating to our acquisition of HPL and the possible
resolution of outstanding energy trading issues. We are unable to
predict whether these discussions will lead to an agreement on these
subjects. If these discussions do not lead to an agreement, there may be
a dispute with Enron concerning our ability to continue utilization of
the Bammel storage facility and certain appurtenant pipelines under the
existing agreements.
We also entered into an agreement with BAM Lease Company which grants
HPL the right to use approximately 65 billion cubic feet of cushion gas
(or pad gas) required for the normal operation of the Bammel gas storage
facility. The Bammel Gas Trust, which purportedly owned approximately 55
billion cubic feet of the gas, had entered into a financing arrangement
in 1997 with Enron and a group of banks. These banks purported to have
certain rights to the gas in certain events of default. In connection
with our acquisition of HPL, the banks entered into an agreement
granting HPL's exclusive use of the cushion gas and released HPL from
liabilities and obligations under the financing arrangement. HPL was
thereafter informed by the banks of a purported default by Enron under
the terms of the referenced financing arrangement. In July 2002, the
banks filed a lawsuit against HPL seeking a declaratory judgment that
they have a valid and enforceable security interest in this cushion gas
which would permit them to cause the withdrawal of this gas from the
storage facility. In September 2002, HPL filed a general denial and
certain counterclaims against the banks. HPL also filed a motion to
dismiss. Management is unable to predict the outcome of this lawsuit or
its impact on our financial position, results of operations and cash
flows.
During 2002 and 2001, we expensed a total of $53 million ($34 million
net of tax) for our estimated loss from the Enron bankruptcy. The amount
expensed 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.
Enron has recently instituted proceedings against other energy trading
counterparties challenging the practice of utilizing offsetting
receivables and payables and related collateral across various Enron
entities. We believe that we have the right to utilize similar
procedures in dealing with payables, receivables and collateral with
Enron entities by offsetting trading payables owed to various Enron
entities against trading receivables due to several AEP subsidiaries. In
this regard in July 2003, Enron sent to AEPES a demand for payment of
approximately $138 million relating to AEPES' termination of trading
contracts which amount does not recognize the right of setoff, discussed
above. We believe we have legal defenses to any challenge that may be
made to the utilization of such offsets, but at this time are unable to
predict the ultimate resolution of this issue.
Shareholder Lawsuits
In the fourth quarter of 2002 and the first quarter of 2003, lawsuits
alleging securities law violations and seeking class action
certification were filed in federal District Court, Columbus, Ohio
against AEP, certain AEP executives, and in some of the lawsuits,
members of the AEP Board of Directors and certain investment banking
firms. The lawsuits claim that we failed to disclose that alleged "round
trip" trades resulted in an overstatement of revenues, that we failed to
disclose that our traders falsely reported energy prices to trade
publications that published gas price indices and that we failed to
disclose that we did not have in place sufficient management controls to
prevent round trip trades or false reporting of energy prices. The
plaintiffs seek recovery of an unstated amount of compensatory damages,
attorney fees and costs. The Court has appointed a lead plaintiff and
allowed the lead plaintiff the opportunity to file an amended complaint.
Also, in the first quarter of 2003, a lawsuit making essentially the
same allegations and demands was filed in state Common Pleas Court,
Columbus, Ohio against AEP, certain executives, members of the Board of
Directors and our independent auditor. We removed this case to federal
District Court in Columbus. The case is pending on plaintiff's motion to
remand. We intend to vigorously defend against these actions.
In the fourth quarter of 2002, two shareholder derivative actions were
filed in state court in Columbus, Ohio against AEP and its Board of
Directors alleging a breach of fiduciary duty for failure to establish
and maintain adequate internal controls over our gas trading operations.
Also, in the fourth quarter of 2002 and the first quarter of 2003, three
lawsuits were filed against AEP, certain executives and AEP's Employee
Retirement Income Security Act (ERISA) Plan Administrator alleging
violations of ERISA in the selection of AEP stock as an investment
alternative and in the allocation of assets to AEP stock. The ERISA
actions are pending in federal District Court, Columbus, Ohio. The
derivative actions and the ERISA actions are in the initial pleading
stage. We intend to vigorously defend against these actions.
California Lawsuit
In November 2002, the Lieutenant Governor of California filed a lawsuit
in Los Angeles County, California Superior Court against forty energy
companies, including AEP, and two publishing companies alleging
violations of California law through alleged fraudulent reporting of
false natural gas price and volume information with an intent to affect
the market price of natural gas and electricity. This case is in the
initial pleading stage and all defendants have filed motions to dismiss.
The plaintiff has moved to dismiss us and has stated an intention to
amend the complaint to add an AEP subsidiary as a defendant. We intend
to vigorously defend against this action.
Texas Commercial Energy, LLP Lawsuit
Texas Commercial Energy, LLP (TCE), a Texas REP, has filed a lawsuit in
federal District Court in Corpus Christi, Texas against us and four AEP
subsidiaries, certain unaffiliated energy companies and ERCOT. The
action alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made
against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price
spikes requiring TCE to post additional collateral and ultimately forced
it into bankruptcy when it was unable to raise prices to its customers
due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary
damages and court costs. Management believes that the claims against us
are without merit. We intend to vigorously defend against the claims.
Bank of Montreal Claim
In March 2003, Bank of Montreal (BOM) terminated all natural gas trading
deals and claimed approximately $34 million was owed to BOM by AEP. In
April 2003, we filed a lawsuit against BOM claiming BOM had acted
contrary to industry practice in calculating termination and liquidation
amounts and that BOM had acknowledged in March 2003 that it owed us
approximately $68 million. Alternatively, we are claiming that BOM owes
us approximately $45 million. Although management is unable to predict
the outcome of this matter, it is not expected to have a material impact
on results of operations, cash flows or financial condition.
Arbitration of Williams Claim
In October 2002, we filed a demand for arbitration with the American
Arbitration Association to initiate formal arbitration proceedings in a
dispute with the Williams Companies (Williams). The proceeding results
from Williams' repudiation of its obligations to provide physical power
deliveries to AEP and Williams' failure to provide the monetary security
required for natural gas deliveries by AEP. Consequently, both parties
claimed default and terminated all outstanding natural gas and electric
power trading deals among the various Williams and AEP affiliates.
Williams claimed that we owed approximately $130 million in connection
with the termination and liquidation of all trading deals. Williams and
AEP settled the dispute and we paid $90 million to Williams in June
2003. The resolution of this matter did not have a material impact on
results of operations or financial condition as we had accrued the
amount paid.
Arbitration of PG&E Energy Trading, LLC Claim
In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately
$22 million was owed by AEP in connection with the termination and
liquidation of all trading deals. In February 2003, PGET initiated
arbitration proceedings. In July 2003, AEP and PGET agreed to a
settlement and we paid approximately $11 million to PGET. The settlement
payment did not have a material impact on results of operations, cash
flows or financial condition as the payment approximated our recorded
liability.
Energy Market Investigation
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), 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, 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.
In March 2003, we received a subpoena from the SEC as part of the SEC's
ongoing investigation of energy trading activities. In August 2002, we
had received an informal data request from the SEC seeking that we
voluntarily provide information. The subpoena sought additional
information and is part of the SEC's formal investigation. we responded
to the subpoena and will continue to cooperate with the SEC.
Management cannot predict what, if any action, any of these governmental
agencies may take with respect to these matters.
FERC Proposed Standard Market Design
In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking which sought to standardize the structure and
operation of wholesale electricity markets across the country. Key
elements of FERC's proposal included standard rules and processes for
all users of the electricity transmission grid, new transmission rules
and policies, and the creation of certain markets to be operated by
independent administrators of the grid in all regions. The FERC issued a
white paper on the proposal in April 2003, in response to the numerous
comments FERC received on its proposal. Until the rule is finalized,
management cannot predict its effect on cash flows and results of
operations.
FERC Proposed Security Standards
As part of the SMD proposed rulemaking, in July 2002, FERC published for
comment proposed security standards. These standards were intended to
ensure that all market participants would have a basic security program
that would effectively protect the electric grid and related market
activities. As proposed, these standards would apply to AEP's power
transmission systems, distribution systems and related areas of
business. The proposed standards have not been adopted. Subsequently, in
2002, the North American Electric Reliability Council (NERC), with
FERC's support, developed a new set of standards to address industry
compliance. These new standards closely parallel the initial, proposed
FERC standards in both content and compliance time frames, and were
approved by the NERC ballot body in June of 2003. We are developing
financial requirements for security implementation and compliance with
these NERC standards. Since these financial requirements are not yet
determined, management cannot predict the impacts of such standards on
future results of operations and cash flows.
9. GUARANTEES
----------
In November 2002, the FASB issued FIN 45 which clarifies the accounting
to recognize a liability related to issuing a guarantee, as well as
additional disclosures of guarantees. This new guidance is an
interpretation of SFAS 5, 57, and 107 and a rescission of FIN 34. The
initial recognition and initial measurement provisions of FIN 45 were
effective on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements of FIN 45 were effective
for financial statements of interim or annual periods ending after
December 15, 2002.
There are no liabilities recorded for guarantees entered into prior to
December 31, 2002 in accordance with FIN 45. There are certain
liabilities recorded for guarantees entered into subsequent to December
31, 2002. These liabilities are immaterial to AEP. 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.
Certain of our subsidiaries have entered into standby letters of credit
(LOC) with third parties. These LOCs cover gas and electricity trading
contracts, construction contracts, insurance programs, security
deposits, debt service reserves, drilling funds and credit enhancements
for issued bonds. All of these LOCs were issued by an AEP subsidiary in
the subsidiaries' ordinary course of business. TCC issued an LOC for
credit enhancement of issued bonds. At June 30, 2003, the maximum future
payments of all the LOCs are approximately $163 million with maturities
ranging from July 2003 to January 2011. TCC's LOC was for approximately
$40.9 million with a maturity date of November 2003. Since we are the
parent to all these 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.
The following subsidiaries have entered into guarantees of third-party
obligations:
CSW Energy and CSW International 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
$3.7 million, which expires June 2020.
Additionally, AEP Utilities guaranteed 50% of the required debt service
reserve for Polk Power Partners, another 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 $4.7 million, which expires July 2010.
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 a revolving credit
agreement, 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 $61 million with maturity dates
ranging from June 2005 to February 2012.
As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining, SWEPCo has agreed to provide
guarantees of mine reclamation in the amount of approximately $85
million. Since SWEPCo uses self-bonding, the guarantee provides for
SWEPCo to commit to use its resources to complete the reclamation in the
event the work is not completed by a third party miner. At June 30,
2003, 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.
It is reasonably possible that due to the guarantees and contracts in
place with Sabine that SWEPCo will consolidate Sabine in the third
quarter of 2003, as a result of the issuance of FIN 46. Upon
consolidation, SWEPCo would record the assets, liabilities, depreciation
expense, minority interest and debt interest expense of Sabine. SWEPCo
would eliminate expenses associated with the mining contract against
Sabine's revenues.
See Note 8 "Commitments and Contingencies" under Power Generation
Facility for disclosure of related guarantees. See Note 13 "Leases" for
disclosure of lease residual value guarantees. See Note 14 "Minority
Interest in Finance Subsidiary" for disclosure of related guarantees.
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 prior to December 31,
2002 due to the uncertainty of future events. In the first and second
quarters of 2003, we entered into several sale agreements as discussed
in Note 11. These sale agreements include indemnifications with a
maximum exposure of approximately $67 million. There are no material
liabilities recorded for any indemnifications entered during the first
six months of 2003. There are no liabilities recorded for any
indemnifications entered prior to December 31, 2002.
We lease certain equipment under a master operating lease. Under the
lease agreement, the lessor is guaranteed to receive up to 87% of the
unamortized balance of the equipment at the end of the lease term. If
the fair market value of the leased equipment is below the unamortized
balance at the end of the lease term, we have committed to pay the
difference between the fair market value and the unamortized balance,
with the total guarantee not to exceed 87% of the unamortized balance.
At June 30, 2003, the maximum potential loss for these lease agreements
was approximately $27 million assuming the fair market value of the
equipment is zero at the end of the lease term.
10. SUSTAINED EARNINGS IMPROVEMENT INITIATIVE
-----------------------------------------
In response to difficult conditions in our business, a Sustained
Earnings Improvement (SEI) initiative was undertaken company-wide in the
fourth quarter of 2002, as a cost-saving and revenue-building effort to
build long-term earnings growth.
Termination benefits expense relating to 1,120 terminated employees
totaling $75.4 million pre-tax was recorded in the fourth quarter of
2002. Of this amount, we paid $9.5 million and $51.2 million to these
terminated employees in the fourth quarter of 2002 and the first
quarter of 2003, respectively. Substantially all SEI related payments
have been made as of June 30, 2003. The termination benefits expense
was classified as Maintenance and Other Operation expense on our
Consolidated Statements of Operations. No additional termination
benefits expense related to the SEI initiative was recorded during
the first and second quarters of 2003.
11. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE
--------------------------------------------------------------
DISPOSITIONS
First Quarter 2003 Dispositions
We completed the sales of C3 Communications, Mutual Energy Service
Company, LLC, our water heater rental program assets and our interest in
AEP Gas Power Systems, LLC. The impact on our results of operations for
the six months ended June 30, 2003 was not significant.
Newgulf Facility
We completed the sale of the Newgulf facility during the second quarter
of 2003 and the impact on earnings was not significant. Newgulf's
Property, Plant and Equipment, net of accumulated depreciation, was
classified on our Consolidated Balance Sheets as held for sale at
December 31, 2002. See the tables at the end of the Assets Held for Sale
section for more detailed information.
Nordic Trading
The transfer of the Nordic Trading business, including its trading
portfolio, to new owners was completed during the second quarter of 2003
and the impact on earnings during the second quarter of 2003 was not
significant. The assets and liabilities of Nordic Trading were
classified on our Consolidated Balance Sheets as held for sale at
December 31, 2002. See the tables at the end of the Assets Held for Sale
section for more detailed information.
DISCONTINUED OPERATIONS
The results of operations of the entities shown below, affecting AEP,
have been classified as Discontinued Operations for all periods
presented. The assets and liabilities of Pushan Power Plant and Eastex
were aggregated on our Consolidated Balance Sheets as Assets Held for
Sale and Liabilities Held for Sale (see table at the end of the Assets
Held For Sale section below for more detailed information):
For the quarter ended June 30, 2003 and 2002:
Pushan Power
SEEBOARD CitiPower Plant Eastex Total
-------- --------- ------------ ------ -----
(in millions)
2003 Revenue $ - $ - $12 $ 15 $ 27
2002 Revenue 311 109 11 16 447
2003 Earnings
(Loss) After Tax $ - $ - $(1) $(6) $ (7)
2002 Earnings
(Loss) After Tax 3 (97) 1 (3) (96)
For the six months ended June 30, 2003 and 2002:
Pushan Power
SEEBOARD CitiPower Plant Eastex Total
-------- --------- ------------ ------ -----
(in millions)
2003 Revenue $ - $ - $27 $ 46 $ 73
2002 Revenue 694 206 26 28 954
2003 Earnings
(Loss) After Tax $ - $ - $(1) $(15) $(16)
2002 Earnings
(Loss) After Tax 36 (108) 3 (5) (74)
ASSETS HELD FOR SALE
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), during 2002, we recorded an estimated
loss on disposal of assets held for sale. The following provides an
update of those assets still held for sale.
Eastex
We currently anticipate that the sale of assets will be completed by the
end of 2003. Results of operations of Eastex have been reclassified as
Discontinued Operations in accordance with SFAS 144. The assets and
liabilities of Eastex have been included on our Consolidated Balance
Sheets as held for sale. See the tables at the end of this section for
more detailed information.
Pushan Power Plant
We currently anticipate that negotiations to sell our interest in the
Pushan Power Plant (Pushan) in Nanyang, China to one of the minority
interest partners will be completed by the second quarter of 2004. This
anticipated closing date is later than originally expected due to
several unusual circumstances including the SARS outbreak. Results of
operations of Pushan have been reclassified as Discontinued Operations
in accordance with SFAS 144. The assets and liabilities of Pushan have
been classified on our Consolidated Balance Sheets as held for sale. See
the tables at the end of this section for more detailed information.
Excess Equipment
In November 2002, as a result of a cancelled development project, we
obtained title to a surplus gas turbine generator. We have been
unsuccessful in finding potential buyers of the unit, including its own
internal generation operators, due to an over-supply of generation
equipment available for sale. Sale of the turbine is currently still
projected before the end of 2003. The Other Assets have been classified
on our Consolidated Balance Sheets as held for sale. See the tables at
the end of this section for more detailed information.
Excess Real Estate
In the fourth quarter of 2002, we began to market an under-utilized
office building in Dallas, TX obtained through the merger with CSW. We
currently anticipate the sale of the facility to be completed by the end
of 2003. The property asset has been classified on our Consolidated
Balance Sheets as held for sale. See the tables at the end of this
section for more detailed information.
The assets and liabilities of the entities held for sale at June 30,
2003 and December 31, 2002 are as follows:
Pushan Power Excess Excess
Eastex Plant Real Estate Equipment Total
June 30, 2003 ------ ------------ ----------- --------- ----
------------- (in millions)
Assets:
Current Assets $20 $ 22 $ - $ - $ 42
Property, Plant and
Equipment, Net - 147 18 - 165
Other Assets - - - 12 12
--- --- --- --- ----
Total Assets
Held for Sale $20 $169 $18 $12 $219
=== ==== === === ====
Liabilities:
Current Liabilities $ 9 $ 21 $ - $ - $ 30
Long-term Debt - 22 - - 22
Other Liabilities - 51 - - 51
--- ---- --- --- ----
Total Liabilities
Held For Sale $ 9 $ 94 $ - $ - $103
=== ==== === === ====
Pushan Excess Water Tele-
Power Newgulf Nordic Real Excess Heater communica-
Eastex Plant Facility Trading Estate Equipment Program tions Total
------ ----- -------- ------- ------ --------- ------- ---------- -----
December 31, 2002 (in millions)
Assets:
Current Assets $15 $ 19 $ - $35 $ - $ - $ 1 $ - $ 70
Property, Plant and
Equipment, Net - 132 6 - 18 - 38 6 200
Other Assets - - - 10 - 12 - - 22
--- ---- --- --- --- --- --- --- ----
Total Assets
Held for Sale $15 $151 $ 6 $45 $18 $12 $39 $ 6 $292
=== ==== === === === === === === ====
Liabilities:
Current Liabilities $ 8 $ 28 - $48 $ - $ - $ - $ - $ 84
Long-term Debt - 25 - - - - - - 25
Other Liabilities 4 26 - 3 - - - - 33
--- ---- --- --- --- --- --- --- ----
Total
Liabilities
Held For Sale $12 $ 79 $ - $51 $ - $ - $ - $ - $142
=== ==== === === === === === === ====
12. 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
o Parent company, which includes corporate related expenditures,
interest income and interest expense
Investments - Gas Operations
o Gas pipeline and storage services
Investments - UK Operations
o International generation of electricity for sale to wholesale
customers
Investments - Other
o Coal mining, bulk commodity barging operations and other energy
supply businesses
The tables below present segment information for the six months ended
June 30, 2003 and 2002. These amounts include certain estimates and
allocations where necessary.
Investments
------------------------------------------
Utility Gas UK Reconciling
Operations Operations Operations Other Adjustments Consolidated
---------- ---------- ---------- ----- ----------- ------------
June 30, 2003 (in millions)
Revenues from:
External Customers $ 5,401 $1,931 $ 112 $ 305 $- $ 7,749
Other Operating Segments - 100 - 28 (128) -
Discontinued Operations - - - (16) - (16)
Cumulative Effect of
Accounting Changes,
net of tax 238 (23) (22) - - 193
Net Income (Loss) 750 (61) (59) (15) - 615
Total Assets 28,539 3,492 1,295 1,814 219 (a) 35,359
Investments
-------------------------------------------
Utility Gas UK Reconciling
Operations Operations Operations Other Adjustments Consolidated
---------- ---------- ---------- -------- ----------- ------------
June 30, 2002
Revenues from:
External Customers $ 4,918 $1,103 $ 134 $ 418 $- $ 6,573
Other Operating Segments - 134 - 78 (212) -
Discontinued Operations - - - (74) - (74)
Cumulative Effect of
Accounting Changes,
net of tax - - - (350) - (350)
Net Income (Loss) 441 (80) 11 (479) - (107)
Total Assets 25,797 5,387 1,707 7,067 844 (a) 40,802
(a) Reconciling adjustments for Total Assets include Assets Held for
Sale and/or Assets of Discontinued Operations.
13. LEASES
------
OPCo has entered into an agreement with JMG Funding LLP (JMG), an
unrelated unconsolidated special purpose entity. JMG has a capital
structure of which 3% is equity from investors with no relationship to
AEP or any of its subsidiaries and 97% is debt from pollution control
bonds and other bonds. JMG was formed to design, construct and lease the
Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber
and leases it to OPCo. The lease is accounted for as an operating lease.
Payments under the operating lease are based on JMG's cost of financing
(both debt and equity) and include an amortization component plus the
cost of administration. OPCo and AEP do not have an ownership interest
in JMG and do not guarantee JMG's debt.
At any time during the lease, OPCo has the option to purchase the Gavin
Scrubber for the greater of its fair market value or adjusted
acquisition cost (equal to the unamortized debt and equity of JMG) or
sell the Gavin Scrubber. The initial 15-year lease term is
non-cancelable. At the end of the initial term, OPCo can renew the
lease, purchase the Gavin Scrubber (terms previously mentioned), or sell
the Gavin Scrubber. In case of a sale at less than the adjusted
acquisition cost, OPCo must pay the difference to JMG.
The use of JMG allows OPCo to enter into an operating lease while
keeping the tax benefits otherwise associated with a capital lease. As
of June 30, 2003, AEP has determined that OPCo will consolidate JMG in
the third quarter of 2003 as a result of the issuance of FIN 46. Upon
consolidation, OPCo will record the assets, liabilities, depreciation
expense, minority interest and debt interest expense of JMG. OPCo will
eliminate operating lease expense against JMG's rental revenues. As of
June 30, 2003, the Company is still reviewing the impact of the
consolidation, but will have to record the cumulative effect (net of
tax) due to a change in accounting principle. OPCo's maximum exposure to
loss as a result of its involvement with JMG is approximately $460
million of outstanding debt and equity of JMG as of June 30, 2003.
On March 31, 2003, OPCo made a prepayment of $90 million under this
operating lease structure. AEP recognizes lease expense on a
straight-line basis over the remaining lease term, in accordance with
SFAS 13 "Accounting for Leases." The asset will be amortized over the
remaining lease term, which ends in the first quarter of 2010.
See Note 8 "Commitments and Contingencies" under Power Generation
Facility for discussion of its 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. We intend to renew the lease for the full twenty years. At the
end of each lease term, we may (a) renew for another five-year term, not
to exceed a total of twenty years, (b) purchase the railcars for the
purchase price amount specified in the lease, projected at the lease
inception to be the then fair market value, or (c) return the railcars
and arrange a third party sale (return-and-sale option). The lease is
accounted for as an operating lease with the future payment obligations
included in the annual lease footnote.
This operating lease agreement allows us to avoid a large initial
capital expenditure, and to spread our railcar cost evenly over the
expected twenty-year usage period. In addition, the lease allows us to
take the income tax benefits otherwise associated with ownership.
Under the lease agreement, the lessor is guaranteed that the sale
proceeds under the return-and-sale option discussed above will equal at
least a lessee obligation amount specified in the lease, which declines
over time from approximately 86% to 77% of the projected fair market
value of the equipment. At June 30, 2003, 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 to an unaffiliated company
under an operating lease. The sublessee may renew the lease for up to
four additional one-year terms.
14. MINORITY INTEREST IN FINANCE SUBSIDIARY
---------------------------------------
In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC
(SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned
consolidated subsidiary of AEP that was capitalized with the assets of
Houston Pipe Line Company and Louisiana Intrastate Gas Company (AEP
subsidiaries) and $321.4 million of AEP Energy Services Gas Holding
Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne)
preferred stock, that was convertible into AEP common stock at market
price on a dollar-for-dollar basis. Caddis was capitalized with $2
million cash and a subscription agreement that represents an
unconditional obligation to fund $83 million from SubOne for a managing
member interest and $750 million from Steelhead Investors LLC
(Steelhead) for a non-controlling preferred member interest. As managing
member, SubOne consolidates Caddis. Steelhead is an unconsolidated
special purpose entity and had an original capital structure of $750
million of which 3% is equity from investors with no relationship to AEP
or any of its subsidiaries and 97% is debt from a syndicate of banks.
The $750 million invested in Caddis by Steelhead was loaned to SubOne.
This intercompany loan to SubOne is due August 2006.
On May 9, 2003, SubOne borrowed $225 million from AEP and used the
proceeds to reduce the outstanding balance of the loan from Caddis,
which Caddis used to reduce the preferred interest held by Steelhead.
This payment eliminated the convertible preferred stock of AEP Gas
Holding and the stock price trigger. The use of Steelhead originally
allowed AEP to limit its risk associated with Houston Pipe Line Company
and Louisiana Intrastate Gas Company.
Under the provisions of the Caddis formation agreements, Steelhead
receives a quarterly preferred return equal to an adjusted floating
reference rate (5.25% and 4.73% for the quarters ended June 30, 2003 and
2002, respectively). Caddis has the right to redeem Steelhead's interest
at any time.
The credit agreement between Caddis and SubOne contains covenants that
restrict certain incremental liens and indebtedness, asset sales,
investments, acquisitions, and distributions. The credit agreement also
contains covenants that impose minimum financial ratios. Non-performance
of these covenants may result in an event of default under the credit
agreement. Through June 30, 2003, AEP has complied with the covenants
contained in the credit agreement. In addition, a default under any
other agreement or instrument relating to AEP and certain subsidiaries'
debt outstanding in excess of $50 million is an event of default under
the credit agreement.
The initial period of Steelhead's investment in Caddis is through August
2006. At the end of the initial period, Caddis will either reset
Steelhead's return rate, re-market Steelhead's interests to new
investors, redeem Steelhead's interests, in whole or in part including
accrued return, or liquidate Caddis in accordance with the provisions of
applicable agreements.
Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events, including a default in the payment of the
preferred return, Steelhead's rights include forcing a liquidation of
Caddis and acting as the liquidator. If Steelhead exercised its rights
to force Caddis to liquidate under these conditions, then AEP would
evaluate whether to refinance at that time or relinquish the assets that
support the intercompany loan to Caddis. Liquidation of Caddis could
negatively impact AEP's liquidity.
Caddis and SubOne are each a limited liability company, with a separate
existence and identity from its members, and the assets of each are
separate and legally distinct from AEP. The results of operations, cash
flows and financial position of Caddis and SubOne are consolidated with
AEP for financial reporting purposes. Steelhead's investment in Caddis
and payments made to Steelhead from Caddis are currently reported on
AEP's Consolidated Statements of Operations and Consolidated Balance
Sheets as Minority Interest in Finance Subsidiary.
AEP's maximum exposure to loss as a result of its involvement with
Steelhead is a $2 million capital investment, $83 million under the
subscription agreement to Caddis for any losses incurred by Caddis and
the cash reserve fund balance of approximately $207 million (as of June
30, 2003) due Caddis for default under the intercompany loan agreement.
The recourse to AEP for the second quarter will increase in the third
quarter 2003 to the full $525 million in order to comply with the
covenants.
The FASB and other accounting constituencies continue to interpret the
application of FIN 46 and SFAS 150. As a result, AEP is continuing to
review the application of these new standards as they relate to the
Steelhead transaction.
15. FINANCING AND RELATED ACTIVITIES
--------------------------------
Long-term debt and other securities issuances and retirements during the
first six months of 2003 were:
Type Principal Interest Due
Company of Debt Amount Rate Date
------- ------- ----------- -------- ----
Issuances (in millions) (%)
---------
AEP Senior Unsecured Notes $500 5.375 2010
AEP Senior Unsecured Notes 300 5.25 2015
APCo Senior Unsecured Notes 200 3.60 2008
APCo Senior Unsecured Notes 200 5.95 2033
APCo Installment Purchase
Contracts 100 5.50 2022
CSPCo Senior Unsecured Notes 250 5.50 2013
CSPCo Senior Unsecured Notes 250 6.60 2033
KPCo Senior Unsecured Notes 75 5.625 2032
OPCo Senior Unsecured Notes 250 5.50 2013
OPCo Senior Unsecured Notes 250 6.60 2033
SWEPCo Senior Unsecured Notes 100 5.375 2015
SWEPCo Secured Note 44 4.47 2011
TCC Senior Unsecured Notes 150 3.00 2005
TCC Senior Unsecured Notes 100 Variable 2005
TCC Senior Unsecured Notes 275 5.50 2013
TCC Senior Unsecured Notes 275 6.65 2033
TNC Senior Unsecured Notes 225 5.50 2013
Type Principal Interest Due
Company of Debt Amount Rate Date
---------- ------- ----------- -------- ----
Retirements (in millions) (%)
-----------
AEP Bank Facility $1,300 Variable 2003
AEP Senior Unsecured Notes 49 6.125 2006
AEP Senior Unsecured Notes 250 5.50 2003
AEP Other Debt 6 Variable 2005
APCo First Mortgage Bonds 70 8.50 2022
APCo First Mortgage Bonds 30 7.80 2023
APCo First Mortgage Bonds 20 7.15 2023
APCo Installment Purchase
Contracts 10 7.875 2013
APCo Installment Purchase
Contracts 40 6.85 2022
APCo Installment Purchase
Contracts 50 6.60 2022
APCo Senior Unsecured Notes 100 7.20 2038
APCo Senior Unsecured Notes 100 7.30 2038
CSPCo First Mortgage Bonds 2 8.70 2022
CSPCo First Mortgage Bonds 15 8.55 2022
CSPCo First Mortgage Bonds 14 8.40 2022
CSPCo First Mortgage Bonds 13 8.40 2022
CSPCo First Mortgage Bonds 13 6.80 2003
CSPCo First Mortgage Bonds 26 6.55 2004
CSPCo First Mortgage Bonds 26 6.75 2004
CSPCo First Mortgage Bonds 40 7.90 2023
CSPCo First Mortgage Bonds 33 7.75 2023
I&M First Mortgage Bonds 75 8.50 2022
I&M First Mortgage Bonds 15 7.35 2023
I&M Junior Debentures 40 8.00 2026
I&M Junior Debentures 125 7.60 2038
KPCo Junior Debentures 40 8.72 2025
OPCo First Mortgage Bonds 30 6.75 2003
PSO First Mortgage Bonds 35 6.25 2003
SWEPCo First Mortgage Bonds 55 6.625 2003
SWEPCo Secured Note 1 4.47 2011
TCC First Mortgage Bonds 18 7.50 2023
TCC First Mortgage Bonds 16 6.875 2003
TCC Securitization Bonds 32 3.54 2005
Non-Registrant:
AEP Subsidiaries Notes Payable 3 Variable 2003-2007
AEP Subsidiaries Revolving Credit
Agreement 306 Variable 2003
AEP Subsidiaries Senior Unsecured Notes 17 6.50 2003
In addition to the transactions reported in the table above, the
following table lists intercompany retirements of debt due to AEP:
Type Principal Interest Due
Company of Debt Amount Rate Date
--------- ------- ----------- -------- ----
Retirements (in millions) (%)
-----------
CSPCo Notes Payable $160 6.501 2006
KPCo Notes Payable 15 4.336 2003
OPCo Notes Payable 240 6.501 2006
OPCo Notes Payable 60 4.336 2003
Non-Registrant:
AEP Subsidiaries Notes Payable 105 4.336 2003
AEP Subsidiaries Notes Payable 12 6.501 2006
Other Matters
In May 2003, a third party exercised its option to call our $250 million
of 5.50% putable callable notes, issued in May 2001, for purchase and
remarketing. On May 15, 2003, we issued $300 million of 5.25% senior
notes due 2015, a portion of which was an exchange for the $250 million
putable callable notes due in 2003.
In July 2003, Ohio Power issued the following Senior Unsecured Notes:
Principal Due
Amount Interest Rate Date
----------- ------------- ----
(in millions) (%)
$225 million 4.85% 2014
$225 million 6.375% 2033
Common Stock
In March 2003, we issued 56 million shares of common stock at $20.95 per
share through an equity offering and received net proceeds of $1,141
million (net of issuance costs of $36 million). Proceeds from the sale
of common stock were used to pay down both short-term and long-term debt
with the balance being held in cash.
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
AEGCo is engaged in the generation and wholesale sale of electric power to two
affiliates under long-term agreements. Operating revenues are derived from the
sale of Rockport Plant energy and capacity to two affiliated companies pursuant
to FERC approved long-term unit power agreements. The unit power agreements
provide for recovery of costs including a FERC approved rate of return on common
equity (12.16% annually) and a return on other capital, net of temporary cash
investments.
Results of Operations
- ---------------------
Net Income increased $50 thousand during the second quarter and decreased $47
thousand in the six month period. The fluctuations in Net Income are a result of
terms in the unit power agreements which limit recovery of return on capital
related to operating and in-service ratios of the Rockport Plant calculated and
adjusted monthly.
Operating Income
Operating Income was virtually unchanged in the quarter and increased $94
thousand year-to-date reflecting recovery in revenues of increased operating
costs in accordance with the unit power agreements.
o Operating Revenues increased as a result of increased recoverable
expenses, primarily fuel, as net generation increased 14% in the
quarter and 30% year-to-date.
o Fuel for Electric Generation expense increased due to increased
generation in 2003 and higher coal costs. Outages during the first
quarter of 2002 reduced the Rockport Plant's availability and
generation in 2002.
o The decreases in Other Operation and Maintenance expenses are
primarily due to higher costs incurred during planned maintenance in
2002.
o The decrease in Taxes Other Than Income Taxes reflects a decline
in the accrual of real and personal property tax for Indiana for the
Rockport Plant, reflecting a favorable change in the tax law
effective March 2002.
o Income Taxes attributable to operations increased primarily due to
state income tax accrual adjustments.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $59,568 $53,356 $119,996 $103,231
------- ------- -------- --------
OPERATING EXPENSES:
Fuel for Electric Generation 29,237 21,535 59,634 39,035
Rent - Rockport Plant Unit 2 17,070 17,070 34,141 34,141
Other Operation 2,443 4,014 4,992 7,236
Maintenance 2,287 2,378 3,938 5,354
Depreciation 5,665 5,642 11,286 11,275
Taxes Other Than Income Taxes 604 907 1,395 1,960
Income Taxes 748 306 1,245 959
------- ------- -------- --------
TOTAL OPERATING EXPENSES 58,054 51,852 116,631 99,960
------- ------- -------- --------
OPERATING INCOME 1,514 1,504 3,365 3,271
NONOPERATING INCOME 19 32 21 34
NONOPERATING EXPENSES 25 94 242 106
NONOPERATING INCOME TAX CREDITS 845 823 1,739 1,655
INTEREST CHARGES 585 547 1,319 1,243
------- ------- -------- --------
NET INCOME $ 1,768 $ 1,718 $ 3,564 $ 3,611
======= ======= ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $18,788 $14,604 $18,163 $13,761
NET INCOME 1,768 1,718 3,564 3,611
CASH DIVIDENDS DECLARED 1,172 1,050 2,343 2,100
------- ------- ------- -------
BALANCE AT END OF PERIOD $19,384 $15,272 $19,384 $15,272
======= ======= ======= =======
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
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $644,324 $637,095
General 4,255 4,728
Construction Work in Progress 7,923 10,390
-------- --------
Total Electric Utility Plant 656,502 652,213
Accumulated Depreciation 369,616 358,174
-------- --------
NET ELECTRIC UTILITY PLANT 286,886 294,039
-------- --------
OTHER PROPERTY AND INVESTMENTS 119 119
-------- --------
CURRENT ASSETS:
Accounts Receivable - Affiliated Companies 22,628 18,454
Fuel 15,956 20,260
Materials and Supplies 5,004 4,913
Prepayments 49 -
-------- --------
TOTAL CURRENT ASSETS 43,637 43,627
-------- --------
REGULATORY ASSETS 5,688 4,970
-------- --------
DEFERRED CHARGES 8,519 6,974
-------- --------
TOTAL ASSETS $344,849 $349,729
======== ========
See Notes to Respective Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $1 per share:
Authorized and Outstanding - 1,000 Shares $ 1,000 $ 1,000
Paid-in Capital 23,434 23,434
Retained Earnings 19,384 18,163
-------- --------
Total Common Shareholder's Equity 43,818 42,597
Long-term Debt 44,806 44,802
-------- --------
TOTAL CAPITALIZATION 88,624 87,399
-------- --------
OTHER NONCURRENT LIABILITIES 1,297 301
-------- --------
CURRENT LIABILITIES:
Advances from Affiliates 26,684 28,034
Accounts Payable:
General - 26
Affiliated Companies 12,994 15,907
Taxes Accrued 6,133 2,327
Rent Accrued - Rockport Plant Unit 2 4,963 4,963
Other 1,105 1,111
-------- --------
TOTAL CURRENT LIABILITIES 51,879 52,368
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
PLANT UNIT 2 108,261 111,046
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credit 51,274 52,943
Amounts Due to Customers for Income Taxes 15,719 16,670
-------- --------
TOTAL REGULATORY LIABILITIES 66,993 69,613
-------- --------
DEFERRED INCOME TAXES 27,795 29,002
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $344,849 $349,729
======== ========
See Notes to Respective Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 3,564 $ 3,611
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Depreciation 11,286 11,275
Deferred Income Taxes (2,158) (2,938)
Deferred Investment Tax Credits (1,668) (1,669)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (2,785) (2,785)
Changes in Certain Assets and Liabilities:
Accounts Receivable (4,174) (6,456)
Fuel, Materials and Supplies 4,213 (3,871)
Accounts Payable (2,939) 29,401
Taxes Accrued 3,806 3,815
Deferred Property Taxes (1,573) (1,786)
Change in Other Assets (751) 43
Change in Other Liabilities 884 355
-------- --------
Net Cash Flows From Operating Activities 7,705 28,995
-------- --------
INVESTING ACTIVITIES - Construction Expenditures (4,012) (5,604)
-------- --------
FINANCING ACTIVITIES:
Change in Advances to/from Affiliates, net (1,350) (22,274)
Dividends Paid (2,343) (2,100)
-------- --------
Net Cash Flows Used For Financing Activities (3,693) (24,374)
------- --------
Net Decrease in Cash and Cash Equivalents - (983)
Cash and Cash Equivalents at Beginning of Period - 983
-------- --------
Cash and Cash Equivalents at End of Period $ - $ -
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,186,000 and $1,132,000
and for income taxes was $2,448,000 and $1,217,000 in 2003 and 2002,
respectively.
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
Net Income increased $70 million and $30 million for the year-to-date and second
quarter, respectively. The increased income is associated with the recognition
of stranded costs in Texas of $70 million and $34 million for the year-to-date
and second quarter, respectively.
Since REPs are the electricity suppliers to retail customers in the ERCOT area,
we sell our generation to the REPs and other market participants and provide
transmission and distribution services to retail customers of the REPs in our
service territory. As a result of the provision of retail electric service by
REPs, effective January 1, 2002, we no longer supply electricity directly to
retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in our sales as further described below.
In December 2002, AEP sold Mutual Energy CPL to an unrelated third party, who
assumed the obligations of the affiliated REP including the provision of
price-to-beat rates under the Texas Restructuring Legislation. Prior to the
sale, during 2002, sales to Mutual Energy CPL were classified as Sales to AEP
Affiliates. Subsequent to the sale, energy transactions with Mutual Energy CPL
are classified as Electric Generation and delivery charges as Electric
Transmission and Distribution.
Operating Income
Operating Income increased by $69 million for the year-to-date and $32 million
for the second quarter due to the following:
o Revenues associated with the recovery of stranded costs in Texas,
mentioned above, were $108 million for the year-to-date and $52
million for the second quarter (see "Texas Restructuring" in Note 6).
o Reliability Must Run (RMR) revenues from ERCOT of $122 million for
the year-to-date and $66 million for the second quarter which
include fuel recovery (see "Texas Plants" in Note 13 in the Annual
Report, as updated by the Current Report on Form 8-K dated May 14,
2003, for discussion of RMR facilities).
o Increased sales to REPs for the second quarter consisting of an
$11 million increase in delivery revenues offset in part by a
decrease of $7 million in generation revenues.
o Other generation sales increased $60 million for the year-to-date and
$20 million for the second quarter primarily resulting from risk
management activities.
o Depreciation and Amortization expense decreased $7 million for the
year-to-date and $9 million for the second quarter due mainly to
decreases resulting from ARO (see Note 2), reduced depreciable plant
due to the mothballing of certain generating units in 2002 and
changes resulting from amortization of regulatory assets.
o Reduced Taxes Other Than Income Taxes of $9 million for the year-to-
date and $4 million for the second quarter resulting from lower
property taxes and state gross receipts taxes stemming from
deregulation in Texas.
The increase in Operating Income was partially offset by:
o Net increases in fuel and purchased power to replace portions of
the energy from the non-RMR mothballed plants and the unscheduled
forced outage at the STP Nuclear Unit (See "Significant Factors"
below). KWHs purchased increased 172% while the total cost
increased 614% due to higher average prices. This increased
purchased power cost was offset by lower generation costs
resulting from the reduced generation from the non-RMR mothballed
units.
o Increases in maintenance expense due to both the forced outage and
a scheduled refueling outage in the first quarter at STP. The
increase in nuclear maintenance over last year was $12 million for
the year-to-date and $7 million for the second quarter.
o An increase in provisions for rate refunds of $35 million for the
year-to-date and $8 million for the second quarter (see "TCC Fuel
Reconciliation" in Note 5).
o Decreased revenues from REPs year-to-date consisting of a decrease in
delivery revenues of $58 million offset in part by an increase of $51
million for generation revenues. The transition to REPs occurred
during January and February of 2002, resulting in the variance for
the year.
o Income Taxes increased $39 million year-to-date and $15 million for
the second quarter due to increases in pre-tax operating book income.
Other Impacts on Earnings
Net nonoperating income and expense increased $5 million year-to-date primarily
due to increased gains from risk management activities.
Interest Charges increased $4 million year-to-date and $3 million for the second
quarter primarily due to less capitalized interest due to declines in the amount
of construction work in process in the current year.
Cumulative Effect of Accounting Change
This amount represents the one-time after-tax effect of the application of EITF
02-3 (see Note 3).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have TCC 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-
In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of TCC's rating for unsecured debt from Baa1 to Baa2. The completion of this
review was a culmination of ratings action started during 2002. With the
completion of the reviews, Moody's has placed AEP and its rated subsidiaries on
stable outlook. In March 2003, S&P lowered AEP and its subsidiaries senior
unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP
subsidiaries.
Cash Flow
Cash flows for the six months ended June 30, 2003 and 2002 were as follows:
2003 2002
------ -------
(in thousands)
Cash and cash equivalents at beginning of period $ 85,420 $ 10,909
Cash flow from (used for):
Operating activities 178,228 (49,869)
Investing activities (56,013) (64,147)
Financing activities (154,964) 131,492
--------- ---------
Net increase (decrease) in cash and cash equivalents (32,749) 17,476
--------- ---------
Cash and cash equivalents at end of period $ 52,671 $ 28,385
========= =========
Operating Activities
Cash flow from operating activities increased $228 million from the prior year
primarily due to a $70 million increase in net income as explained above and
accounts receivables changes related to reduced levels of risk management
activities, offset by the non-cash Texas wholesale clawback recorded in 2003.
Investing Activities
Construction expenditures in 2003 versus 2002 decreased by $8 million. The
current year investment expenditures of $56 million were primarily focused on
improved service reliability projects for transmission and distribution systems.
Financing Activities
Net cash flow used for financing activities increased $286 million for the
current year versus prior year. Prior year funds were used to pay down term debt
and retire common stock, whereas current year proceeds were primarily used to
pay down short-term debt.
Financing Activity
TCC issued $100 million of unsecured senior notes due 2005 at a variable rate,
$150 million of unsecured senior notes due 2005 at a coupon of 3.0%, $275
million of unsecured senior notes due 2013 at a coupon of 5.50% and $275 million
of unsecured senior notes due 2033 at a coupon of 6.65%. The proceeds from the
bond issuances were used to repay a bank facility, short-term debt, $18 million
of first mortgage bonds due 2023 at 7.50% and for other corporate purposes.
During the first quarter of 2003, TCC retired $16 million of first mortgage
bonds at maturity and $32 million of securitization bonds due 2005. See Note 12
for additional information related to financing activity.
Significant Factors
- -------------------
Possible Divestitures
In June 2003, we began actively seeking buyers for 4,497 megawatts of
unregulated generation capacity in Texas to establish a market price for
calculation of stranded cost (see Note 6).
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. If we choose to
dispose of these assets, we may realize non-recurring losses in the aggregate
that could have a material impact on our results of operations, cash flows and
financial condition.
Nuclear Plant Outage
In April 2003, engineers at STP, during inspections conducted regularly as part
of scheduled refueling outages, found wall cracks in two bottom mounted
instrument guide tubes of STP Unit 1. These cracks have been repaired and the
unit is expected to return to service in late summer. AEP's share of the direct
cost of repair is approximately $6 million through June 30, 2003. STP officials
are working closely with the NRC to safely return the unit to service. We have
commitments to provide power to customers during the outage. Therefore, we will
be subject to fluctuations in the market prices of electricity and purchased
replacement energy could be a significant cost and could affect our results of
operations and financial position.
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the 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.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Domestic Power
(in thousands)
Beginning Balance December 31, 2002 $ 5,414
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (1,883)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) -
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission 187
Changes in Fair Value of Risk Management
Contracts (d) (72)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) -
-------
Total MTM Risk Management Contract Net
Assets 3,646
Net Non-Trading Related Derivative Contracts (1,205)
-------
Net Fair Value of Risk Management and Derivative
Contracts June 30, 2003 $ 2,441
=======
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior
to 2003.
(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 2003. 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 2003.
(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.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $786 $855 $287 $255 $ 81 $ - $2,264
Prices Based on Models and Other
Valuation Methods (b) 51 113 125 218 220 655 1,382
---- ---- ---- ---- ---- ---- ------
Total $837 $968 $412 $473 $301 $655 $3,646
==== ==== ==== ==== ==== ==== ======
(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.
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. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2003
Domestic
Power
--------
(in thousands)
Accumulated OCI, December 31, 2002 $ (36)
----------------------------------
Changes in Fair Value (a) (767)
Reclassifications from OCI to Net
Income (b) 20
-----
Accumulated OCI Derivative Gain (Loss)
June 30, 2003 $(783)
=====
(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 OCI 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 Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $532 thousand loss.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
June 30, 2003 December 31, 2002
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$109 $742 $413 $109 $115 $353 $126 $26
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electric Generation, Transmission and Distribution $409,796 $ 75,139 $ 821,179 $ 195,187
Sales to AEP Affiliates 72,650 285,252 89,625 444,114
-------- -------- -------- ---------
TOTAL OPERATING REVENUES 482,446 360,391 910,804 639,301
-------- -------- --------- ---------
OPERATING EXPENSES:
Fuel for Electric Generation 21,430 22,738 48,769 49,727
Fuel from Affiliates for Electric Generation 44,911 67,218 83,200 94,557
Purchased Electricity for Resale 116,654 5,972 188,776 9,984
Purchased Electricity from AEP Affiliates 7,210 12,564 18,772 20,491
Other Operation 70,290 71,975 139,692 137,961
Maintenance 21,811 14,782 37,910 25,741
Depreciation and Amortization 51,860 60,923 95,933 102,770
Taxes Other Than Income Taxes 19,783 23,474 42,762 51,396
Income Taxes 31,894 16,426 66,377 26,910
-------- -------- --------- ---------
TOTAL OPERATING EXPENSES 385,843 296,072 722,191 519,537
-------- -------- --------- ---------
OPERATING INCOME 96,603 64,319 188,613 119,764
NONOPERATING INCOME 7,901 4,472 18,063 14,003
NONOPERATING EXPENSES 5,637 3,478 10,832 12,865
NONOPERATING INCOME TAX EXPENSE (CREDIT) 240 (648) 798 (515)
INTEREST CHARGES 35,040 32,426 67,022 63,437
-------- -------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 63,587 33,535 128,024 57,980
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) - - 122 -
-------- -------- --------- ---------
NET INCOME 63,587 33,535 128,146 57,980
PREFERRED STOCK DIVIDEND REQUIREMENTS 61 61 121 121
-------- -------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $ 63,526 $ 33,474 $ 128,025 $ 57,859
======== ======== ========= =========
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 SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- ------------- ------------------ ------
(in thousands)
JANUARY 1, 2002 $168,888 $405,015 $ 826,197 $ - $1,400,100
Redemption of Common Stock (113,596) (272,409) (386,005)
Common Stock Dividends (77,004) (77,004)
Preferred Stock Dividends (121) (121)
----------
936,970
----------
Comprehensive Income:
Other Comprehensive Income 263 263
Net Income 57,980 57,980
----------
Total Comprehensive Income 58,243
-------- -------- --------- ------- ----------
JUNE 30, 2002 $ 55,292 $132,606 $ 807,052 $ 263 $ 995,213
======== ======== ========= ======= ==========
JANUARY 1, 2003 $ 55,292 $132,606 $ 986,396 $(73,160) $1,101,134
Common Stock Dividends (60,401) (60,401)
Preferred Stock Dividends (121) (121)
----------
1,040,612
----------
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (747) (747)
Net Income 128,146 128,146
----------
Total Comprehensive Income 127,399
-------- -------- ---------- -------- ----------
JUNE 30, 2003 $ 55,292 $132,606 $1,054,020 $(73,907) $1,168,011
======== ======== ========== ======== ==========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 3,001,126 $2,903,942
Transmission 757,405 698,964
Distribution 1,336,867 1,296,731
General 261,065 258,386
Construction Work in Progress 82,170 200,947
Nuclear Fuel 270,570 266,766
---------- ----------
Total Electric Utility Plant 5,709,203 5,625,736
Accumulated Depreciation and Amortization 2,359,185 2,405,492
---------- ----------
NET ELECTRIC UTILITY PLANT 3,350,018 3,220,244
---------- ----------
OTHER PROPERTY AND INVESTMENTS 3,991 3,977
---------- ----------
SECURITIZED TRANSITION ASSETS 716,404 734,591
---------- ----------
LONG-TERM RISK MANAGEMENT ASSETS 16,382 4,392
----------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 52,671 85,420
Advances to/from Affiliates, net 51,501 -
Accounts Receivable:
General 220,864 113,543
Affiliated Companies 86,329 121,324
Allowance for Uncollectible Accounts (256) (346)
Fuel Inventory 20,475 32,563
Materials and Supplies 47,225 51,593
Accrued Utility Revenues 42,425 27,150
Risk Management Assets 25,983 22,493
Prepayments and Other Current Assets 3,670 2,133
---------- ----------
TOTAL CURRENT ASSETS 550,887 455,873
---------- ----------
REGULATORY ASSETS 608,119 458,552
---------- ----------
REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION 320,895 336,444
---------- ----------
NUCLEAR DECOMMISSIONING TRUST FUND 108,547 98,474
---------- ----------
DEFERRED CHARGES 74,085 43,891
---------- ----------
TOTAL ASSETS $5,749,328 $5,356,438
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
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
Accumulated Other Comprehensive Income (Loss) (73,907) (73,160)
Retained Earnings 1,054,020 986,396
---------- ----------
Total Common Shareholder's Equity 1,168,011 1,101,134
Preferred Stock 5,942 5,942
CPL - Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of TCC 136,250 136,250
Long-term Debt 1,962,660 1,209,434
---------- ----------
TOTAL CAPITALIZATION 3,272,863 2,452,760
---------- ----------
OTHER NONCURRENT LIABILITIES 324,637 74,572
---------- ----------
CURRENT LIABILITIES:
Short-term Debt - Affiliates - 650,000
Long-term Debt Due Within One Year 209,705 229,131
Advances to/from Affiliates, net - 126,711
Accounts Payable - General 113,437 72,199
Accounts Payable - Affiliated Companies 78,974 36,242
Customer Deposits 2,271 666
Taxes Accrued 73,068 24,791
Interest Accrued 43,595 51,205
Risk Management Liabilities 33,776 19,811
Other 19,191 36,698
---------- ----------
TOTAL CURRENT LIABILITIES 574,017 1,247,454
---------- ----------
DEFERRED INCOME TAXES 1,256,646 1,261,252
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 115,082 117,686
---------- ----------
LONG-TERM RISK MANAGEMENT LIABILITIES 6,148 1,713
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 199,935 201,001
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $5,749,328 $5,356,438
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 128,146 $ 57,980
Adjustments to Reconcile Net Income to Net Cash Flows
From (Used For) Operating Activities:
Depreciation and Amortization 95,933 102,770
Deferred Income Taxes 13,369 (18,103)
Deferred Investment Tax Credits (2,603) (2,603)
Cumulative Effect of Accounting Change (122) -
Mark-to-Market of Risk Management Contracts 1,955 3,932
Texas Wholesale Clawback (108,400) -
Changes in Certain Assets and Liabilities:
Accounts Receivable, net (72,416) (270,791)
Fuel, Materials and Supplies 16,456 (1,071)
Interest Accrued (7,610) 6,107
Accrued Utility Revenues (15,275) -
Accounts Payable 83,970 106,693
Taxes Accrued 48,277 25,651
Deferred Property Tax (20,100) (19,120)
Change in Other Assets 8,433 (38,746)
Change in Other Liabilities 8,215 (2,568)
--------- ---------
Net Cash Flows From (Used For) Operating Activities 178,228 (49,869)
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (56,013) (64,147)
Other - -
--------- ---------
Net Cash Flows Used For Investing Activities (56,013) (64,147)
--------- ---------
FINANCING ACTIVITIES:
Change in Short-term Debt-Affiliates (650,000) 200,000
Issuance of Long-term Debt 800,000 796,613
Retirement of Long-term Debt (66,230) (150,000)
Change in Advances to/from Affiliates, net (178,212) (251,992)
Retirement of Common Stock - (386,004)
Dividends Paid on Common Stock (60,401) (77,004)
Dividends Paid on Cumulative Preferred Stock (121) (121)
--------- ---------
Net Cash Flows From (Used For) Financing Activities (154,964) 131,492
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (32,749) 17,476
Cash and Cash Equivalents at Beginning of Period 85,420 10,909
--------- ---------
Cash and Cash Equivalents at End of Period $ 52,671 $ 28,385
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $72,918,000 and
$40,588,000 and for income taxes was $7,803,000 and $44,322,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
Net Income increased $23 million year-to-date and $17 million for the second
quarter primarily due to Reliability Must Run (RMR) margins from ERCOT (see
"Texas Plants" in Note 13 in the Annual Report, as updated by the Current Report
on Form 8-K dated May 14, 2003, for discussion of RMR facilities) and increased
revenues from generation sales, mostly to REPs in Texas.
Since REPs are the electricity suppliers to retail customers in the ERCOT area,
we sell our generation to the REPs and other market participants and provide
transmission and distribution services to retail customers of the REPs in our
service territory. As a result of the provision of retail electric service by
REPs effective January 1, 2002, we no longer supply electricity directly to
retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in our sales as further described below.
In December 2002, AEP sold Mutual Energy WTU to an unrelated third party, who
assumed the obligations of the affiliated REP, including the provision of
price-to-beat rates under the Texas Restructuring Legislation. Prior to the
sale, during 2002, sales to Mutual Energy WTU were classified as Sales to AEP
Affiliates. Subsequent to the sale, energy transactions with Mutual Energy WTU
are classified as Electric Generation and delivery charges as Electric
Transmission and Distribution.
Operating Income
Operating Income increased by $17 million year-to-date and $18 million for the
second quarter primarily due to the following:
o RMR stand-by revenues from ERCOT of $7 million year-to-date and $4
million for the second quarter.
o Increased revenues from ERCOT for scheduling and balancing services of $13
million year-to-date and $3 million for the second quarter.
o Reduction in provision for rate refunds in the second quarter of $3
million.
o Reduced Other Operation and Maintenance expenses of $7 million year-to-date
and $4 million for the second quarter resulting from the Sustained
Earnings Improvement program, reduced expenses for employee benefits due to
revaluations, and reduced AEPSC billings for customer-related charges.
o Reduced Depreciation and Amortization of $3 million year-to-date and $1
million for the second quarter mainly from the mothballing of several
plants in late 2002.
o Reduced Taxes Other Than Income Taxes of $3 million year-to-date and
$2 million for the second quarter due mainly to declines in gross receipts
and property taxes due in large part to the taxable revaluation of plants.
The increase in Operating Income was partially offset by:
o Increased Income Tax Expense (Credit) of $12 million for the year-to-date
and $10 million for the second quarter due to increases in pre-tax
operating book income.
o Increased provision for rate refunds for the year-to-date of $9 million
(see "TNC Fuel Reconciliation" in Note 5).
o Increased fuel and purchased power expenses of $30 million year-to-date
and $12 million for the second quarter due mainly to higher prices
resulting from increased natural gas prices. KWH generation decreased
due to the mothballing of several plants in late 2002 and KWH purchases
increased to compensate for the mothballing of plants.
Other Impacts on Earnings
Net nonoperating income and expense increased $3 million year-to-date primarily
due to a $1 million increase in income from significantly higher levels of line
construction work for others and a $4 million increase in income from risk
management activities.
Cumulative Effect of Accounting Changes
The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 (see Note 3).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have TNC 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-
In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. TNC had its mortgage bond debt downgraded from
A2 to A3. The completion of this review was a culmination of ratings action
started during 2002. In March 2003, S&P lowered AEP and its subsidiaries senior
unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP
subsidiaries.
Financing Activities
We issued $225 million of unsecured senior notes due 2013 at a coupon of 5.50%.
The proceeds from the bond issuance were used to repay an April 2003 bank
facility, short-term debt and other corporate purposes. See Note 12 for
additional information related to financing activity.
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the 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.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Domestic Power
--------------
(in thousands)
Beginning Balance December 31, 2002 $2,043
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (160)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) -
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission 20
Changes in Fair Value of Risk Management
Contracts (d) 2,392
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) 673
------
Total MTM Risk Management Contract Net
Assets 4,968
Net Non-Trading Related Derivative
Contracts (499)
------
Net Fair Value of Risk Management and Derivative
Contracts June 30, 2003 $4,469
======
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
include realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior
to 2003.
(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 2003. 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 2003.
(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.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- ------
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $1,073 $1,165 $391 $347 $111 $ - $3,087
Prices Based on Models and Other
Valuation Methods (b) 69 153 171 296 300 892 1,881
------ ------ ---- ---- ---- ---- ------
Total $1,142 $1,318 $562 $643 $411 $892 $4,968
====== ====== ==== ==== ==== ==== ======
(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.
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. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2003
Domestic
Power
-----
(in thousands)
Accumulated OCI, December 31, 2002 $ (15)
----------------------------------
Changes in Fair Value (a) (317)
Reclassifications from OCI to Net
Income (b) 8
------
Accumulated OCI Derivative Gain (Loss)
June 30, 2003 $ (324)
======
(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 OCI 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 Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $220 thousand loss.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
June 30, 2003 December 31, 2002
(in thousands) (in thousands)
End High Average Low End High Average Low
- --- ---- ------- --- --- ---- ------- ---
$45 $307 $171 $45 $48 $146 $52 $11
AEP TEXAS NORTH COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electric Generation, Transmission and Distribution $103,136 $ 40,225 $216,629 $ 93,334
Sales to AEP Affiliates 33,670 64,227 36,439 114,744
-------- -------- -------- --------
TOTAL OPERATING REVENUES 136,806 104,452 253,068 208,078
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel for Electric Generation 8,278 9,299 19,739 18,013
Fuel from Affiliates for Electric Generation 10,917 23,543 17,002 39,809
Purchased Electricity for Resale 26,723 7,415 51,501 13,928
Purchased Electricity from AEP Affiliates 16,449 10,559 35,794 22,209
Other Operation 22,365 24,907 42,984 49,077
Maintenance 6,012 7,050 10,153 11,406
Depreciation and Amortization 9,723 11,072 19,255 22,641
Taxes Other Than Income Taxes 3,432 5,726 9,465 12,026
Income Tax Expense (Credit) 9,664 (468) 14,067 2,475
-------- -------- -------- --------
TOTAL OPERATING EXPENSES 113,563 99,103 219,960 191,584
-------- -------- -------- --------
OPERATING INCOME 23,243 5,349 33,108 16,494
NONOPERATING INCOME 17,833 6,980 31,296 5,492
NONOPERATING EXPENSES 17,113 5,688 28,672 7,060
NONOPERATING INCOME TAX EXPENSE (CREDIT) 142 358 481 (631)
INTEREST CHARGES 5,899 5,608 10,564 10,890
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 17,922 675 24,687 4,667
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) - - 3,071 -
-------- -------- -------- --------
NET INCOME 17,922 675 27,758 4,667
PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26 52 52
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 17,896 $ 649 $ 27,706 $ 4,615
======== ======== ======== ========
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 COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------ -----
(in thousands)
JANUARY 1, 2002 $137,214 $2,351 $105,970 $ - $245,535
Common Stock Dividends (13,498) (13,498)
Preferred Stock Dividends (52) (52)
--------
231,985
--------
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Power Hedges 78 78
Net Income 4,667 4,667
--------
Total Comprehensive Income 4,745
-------- ------ -------- ------- --------
JUNE 30, 2002 $137,214 $2,351 $ 97,087 $ 78 $236,730
======== ====== ======== ======= ========
JANUARY 1, 2003 $137,214 $2,351 $ 71,942 $(30,763) $180,744
Common Stock Dividends (4,970) (4,970)
Preferred Stock Dividends (52) (52)
--------
175,722
--------
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (309) (309)
Unrealized Loss on Minimum
Pension Liability (7) (7)
Net Income 27,758 27,758
--------
Total Comprehensive Income 27,442
-------- ------ -------- -------- --------
JUNE 30, 2003 $137,214 $2,351 $ 94,678 $(31,079) $203,164
======== ====== ======== ======== ========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 356,889 $ 353,087
Transmission 256,304 254,483
Distribution 447,789 445,486
General 109,892 111,679
Construction Work in Progress 42,187 37,012
---------- ----------
Total Electric Utility Plant 1,213,061 1,201,747
Accumulated Depreciation and Amortization 524,323 521,792
---------- ----------
NET ELECTRIC UTILITY PLANT 688,738 679,955
---------- ----------
OTHER PROPERTY AND INVESTMENTS 1,203 1,213
---------- ----------
LONG-TERM RISK MANAGEMENT ASSETS 6,637 2,248
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 2,952 1,219
Advances to Affiliates 11,905 -
Accounts Receivable:
Customers 55,213 62,660
Affiliated Companies 25,505 43,632
Allowance for Uncollectible Accounts (4,746) (5,041)
Fuel Inventory 8,598 12,677
Materials and Supplies 9,345 9,574
Accrued Utility Revenues 7,425 6,829
Risk Management Assets 6,237 4,130
Prepayments and Other 966 1,070
---------- ----------
TOTAL CURRENT ASSETS 123,400 136,750
---------- ----------
REGULATORY ASSETS 43,477 45,097
---------- ----------
DEFERRED CHARGES 25,440 11,912
---------- ----------
TOTAL ASSETS $ 888,895 $ 877,175
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
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
Accumulated Other Comprehensive Income (Loss) (31,079) (30,763)
Retained Earnings 94,678 71,942
-------- --------
Total Common Shareholder's Equity 203,164 180,744
Cumulative Preferred Stock Not Subject to
Mandatory Redemption 2,367 2,367
Long-term Debt 333,486 132,500
-------- --------
TOTAL CAPITALIZATION 539,017 315,611
-------- --------
OTHER NONCURRENT LIABILITIES 41,079 28,861
-------- --------
CURRENT LIABILITIES:
Short-term Debt - Affiliates - 125,000
Long-term Debt Due Within One Year 24,036 -
Advances from Affiliates - 80,407
Accounts Payable - General 19,670 32,714
Accounts Payable - Affiliated Companies 27,276 76,217
Customer Deposits 453 117
Taxes Accrued 19,831 3,697
Interest Accrued 6,610 2,776
Risk Management Liabilities 5,969 3,801
Other 12,463 17,414
-------- --------
TOTAL CURRENT LIABILITIES 116,308 342,143
-------- --------
DEFERRED INCOME TAXES 118,113 117,521
-------- --------
DEFERRED INVESTMENT TAX CREDITS 20,750 21,510
-------- --------
LONG-TERM RISK MANAGEMENT LIABILITIES 2,436 557
-------- --------
REGULATORY LIABILITIES AND DEFERRED CREDITS 51,192 50,972
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $888,895 $877,175
======== ========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 27,758 $ 4,667
Adjustments to Reconcile Net Income to Net Cash Flows
From (Used For) Operating Activities:
Depreciation and Amortization 19,255 22,641
Deferred Income Taxes (1,079) 1,470
Deferred Investment Tax Credits (760) (636)
Cumulative Effect of Accounting Changes (3,071) -
Mark-to-Market of Risk Management Contracts (2,905) (1,134)
Changes in Certain Assets and Liabilities:
Accounts Receivable, net 25,279 (74,776)
Fuel, Materials and Supplies 4,308 4,995
Accrued Utility Revenues (596) -
Accounts Payable (61,985) 37,983
Taxes Accrued 16,134 1,145
Fuel Recovery - (2,051)
Deferred Property Taxes (6,645) (7,175)
Change in Other Assets (7,657) (16,944)
Change in Other Liabilities 12,045 (2,018)
--------- ---------
Net Cash Flows From (Used For) Operating Activities 20,081 (31,833)
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (21,609) (25,154)
Other 595 -
--------- ---------
Net Cash Flows Used For Investing Activities (21,014) (25,154)
--------- ---------
FINANCING ACTIVITIES:
Change in Short-term Debt-Affiliates (125,000) -
Issuance of Long-term Debt 225,000 -
Change in Advances to/from Affiliates, net (92,312) 69,991
Dividends Paid on Common Stock (4,970) (13,498)
Dividends Paid on Cumulative Preferred Stock (52) (52)
-------- ---------
Net Cash Flows From Financing Activities 2,666 56,441
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 1,733 (546)
Cash and Cash Equivalents at Beginning of Period 1,219 2,454
-------- ---------
Cash and Cash Equivalents at End of Period $ 2,952 $ 1,908
======== =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $5,525,000 and
$9,481,000 and for income taxes was $(1,305,000) and $2,408,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income for the first half of 2003 increased $69 million over the prior year
period primarily due to the Cumulative Effect of Accounting Changes of $77
million recorded in the first quarter of 2003 and improved margins on higher
overall sales. These increases were partially offset by a $25 million decrease
in Nonoperating Income primarily due to reduced gains from risk management
activities.
Net Income for the second quarter of 2003 decreased $32 million primarily due to
a $15 million increase in capacity charges included in Purchased Electricity
from AEP Affiliates and a $15 million decrease in Nonoperating Income primarily
due to reduced gains from risk management activities. The cost of the AEP Power
Pool's generating capacity is allocated among the Pool members based on their
relative peak demands and generating reserves through the payment of capacity
charges and the receipt of capacity credits. We, as a member of the AEP Power
Pool, share in the revenues and costs of marketing and activities conducted on
our behalf by the AEP Power Pool. Our relative share of the AEP Power Pool
revenues and expenses increased over the prior periods as a result of our
reaching a new peak demand in January 2003, which increased our allocation
factor.
Operating Income
Operating Income for the second quarter of 2003 decreased by $16 million from
2002 primarily due to the following:
o An increase in Purchased Electricity from AEP Affiliates of $25 million
reflecting the increased capacity charges described above and the
increase in our relative share of the AEP Power Pool expenses.
o An increase in Maintenance expenses comprised of an increase in
power plant maintenance at the Amos and Sporn plants for repairs,
combined with an increase in distribution line maintenance due to
severe storm damage, for a combined maintenance increase of $9
million.
o A decline in retail revenues of $12 million primarily due to
decreased residential sales reflecting the mild weather in the
second quarter of 2003 and decreased industrial sales reflecting
the continued sluggish economy. Cooling degree-days for the
quarter decreased 52% from the prior period.
The decrease in Operating Income for the second quarter of 2003 was partially
offset by:
o Higher non-affiliated system sales and Sales to AEP Affiliates
reflecting an increase in the volume of AEP Power Pool
transactions, as well as our relative share based on the higher
allocation factor.
o A decrease in income taxes of $11 million primarily due to the decrease in
pre-tax operating book income.
Operating Income for the first half of 2003 increased $15 million primarily due
to the following:
o AEP Power Pool sales volume increased over 2002, as well as our relative
share based on the higher allocation factor. In addition, our residential
MWH increased 8% year-to-date primarily due to the severe winter weather
in the first quarter of 2003.
o A decrease in Depreciation and Amortization expense of $12 million
due primarily to the adoption of SFAS 143 (see Note 2). Additionally,
we have reduced depreciation and amortization expense related to the
amortization of generation related regulatory assets over the transition
period due to the return to SFAS 71 for the West Virginia jurisdiction
in the first quarter of 2003.
The increase in Operating Income for the first half of 2003 was partially offset
by:
o An increase of $45 million in power costs primarily due to a year-over-year
increase of $23 million in capacity charges and the increase in our
relative share of AEP Power Pool expenses.
o An increase in Maintenance expense of $16 million, due primarily to
increased maintenance at Amos and Sporn plants and maintenance of
overhead lines required due to the severe storm damage in 2003.
Other Impacts on Earnings
Nonoperating Income decreased $15 million and $25 million for the quarter and
six months ended June 30, 2003, respectively, primarily due to a decrease in
gains from risk management activities. The decreases in Nonoperating Income Tax
Expense for both periods were a result of the decreases in Nonoperating Income.
Interest Charges increased $6 million and $8 million for the quarter and six
months ended June 30, 2003, respectively, primarily due to the effects of the
refinancing activities. (See Financing Activities).
Cumulative Effect of Accounting Changes
The Cumulative Effect of Accounting Changes is due to the implementation of SFAS
143 and EITF 02-03 (see Notes 2 and 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 Baa1 BBB A-
Senior Unsecured Debt Baa2 BBB BBB+
In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of our rating for unsecured debt from Baa1 to Baa2. The completion of this
review was a culmination of ratings action started during 2002. In March 2003,
S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB
along with the first mortgage bonds of AEP subsidiaries.
Cash Flow
Cash flows for six months ended June 30, 2003 and 2002 were as follows:
2003 2002
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $ 4,285 $ 13,663
Cash flow from (used for):
Operating activities 262,505 121,804
Investing activities (113,158) (128,270)
Financing activities (142,962) (5,893)
--------- ---------
Net increase (decrease) in cash and cash equivalents 6,385 (12,359)
--------- ---------
Cash and cash equivalents at end of period $ 10,670 $ 1,304
========= ========
Operating Activities
Cash flow from operating activities increased $141 million primarily due to
increases in various accounts receivable balances in the six months ended June
30, 2003.
Investing Activities
Construction expenditures in 2003 versus 2002 decreased $14 million. The current
year expenditures of $115 million were focused on improved service reliability
for transmission and distribution, as well as environmental upgrades.
Financing Activities
During the first half of 2003, we had greater net retirements of long-term debt
and advances to affiliates over last year.
Financing Activity
In 2003, we redeemed the following bonds:
Coupon
Or Stated Call Principal
Rate Rate Due Date Amounts
----- ---- -------- -------
% % (in millions)
- -
8.50 100 2022 $70
7.15 100 2023 20
7.80 103.90 2023 30
7.20 100 2038 100
7.30 100 2038 100
See Note 12 for additional information related to financing activity.
Significant Factors
- -------------------
Federal EPA Complaint and Notice of Violation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", APCo and certain affiliated companies have been
involved in litigation since 1999 regarding generating plant emissions under the
Clean Air Act. Federal EPA and a number of states alleged APCo and certain
affiliated companies and eleven unaffiliated utilities made modifications to
generating units at coal-fired generating plants in violation of the Clean Air
Act. Federal EPA filed complaints against AEP subsidiaries in U.S. District
Court for the Southern District of Ohio. A separate lawsuit initiated by certain
special interest groups was consolidated with the Federal EPA case. The alleged
modification of the generating units occurred 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 Clear Air Act proceedings and
is 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. In the event 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. See Note 7 for
further discussion.
NOx Reductions
Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
under the Clean Air Act requiring substantial reductions in NOx emissions in a
number of eastern states, including certain states in which the AEP System's
generating plants are located. The compliance date for the rules is May 31,
2004.
We are installing selective catalytic reduction (SCR) technology and non-SCR
technology to reduce NOx emissions on certain units to comply with these rules.
Our estimates indicate that compliance with the rules could result in required
capital expenditures of approximately $462 million. The actual cost to comply
could be significantly different than the estimates depending upon the
compliance alternatives selected to achieve reductions in NOx emissions. Unless
any capital or operating costs for additional pollution control equipment are
recovered from customers, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition (see Note 7).
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the 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.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Domestic Power
--------------
(in thousands)
Beginning Balance December 31, 2002 $ 96,852
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (39,981)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 474
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (4,664)
Changes in Fair Value of Risk Management
Contracts (d) 16,072
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (e) 4,002
--------
Total MTM Risk Management Contract Net
Assets 72,755
Net Non-Trading Related Derivative
Contracts (3,594)
--------
Net Fair Value of Risk Management and Derivative
Contracts June 30, 2003 $ 69,161
========
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior to
2003.
(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 2003. 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 2003.
(d)"Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather, etc.
(e)"Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Operations. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $15,531 $17,672 $5,666 $5,025 $1,605 $ - $45,499
Prices Based on Models and Other
Valuation Methods (b) 1,006 2,223 2,474 4,293 4,340 12,920 27,256
------- ------- ------ ------ ------ ------- -------
Total $16,537 $19,895 $8,140 $9,318 $5,945 $12,920 $72,755
======= ======= ====== ====== ====== ======= =======
(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.
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. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2003
Domestic Foreign
Power Currency Interest Rate Consolidated
-------- -------- -------- --------
(in thousands)
Accumulated OCI, December 31, 2002 $ (394) $(190) $(1,336) $(1,920)
----------------------------------
Changes in Fair Value (a) (2,229) - (1,156) (3,385)
Reclassifications from OCI to Net
Income (b) 138 3 131 272
------- ---- ------- -------
Accumulated OCI Derivative Gain (Loss)
June 30, 2003 $(2,485) $(187) $(2,361) $(5,033)
======= ===== ======= =======
(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 OCI 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 Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $1,894 thousand loss.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR year-to-date:
June 30, 2003 December 31, 2002
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$346 $2,354 $1,311 $346 $1,289 $3,948 $1,412 $286
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electric Generation, Transmission and
Distribution $ 389,255 $ 382,081 $868,588 $801,880
Sales to AEP Affiliates 55,496 49,934 112,391 92,740
---------- ---------- -------- --------
TOTAL OPERATING REVENUES 444,751 432,015 980,979 894,620
---------- ---------- -------- --------
OPERATING EXPENSES:
Fuel for Electric Generation 112,680 107,160 232,545 214,650
Purchased Electricity for Resale 15,262 14,945 32,380 28,461
Purchased Electricity from AEP Affiliates 83,805 58,717 164,525 119,497
Other Operation 66,626 63,417 128,741 130,376
Maintenance 36,827 27,638 69,565 53,489
Depreciation and Amortization 46,065 46,909 82,073 93,681
Taxes Other Than Income Taxes 22,272 25,050 47,351 50,045
Income Taxes 12,158 22,955 62,059 57,643
---------- ---------- -------- --------
TOTAL OPERATING EXPENSES 395,695 366,791 819,239 747,842
---------- ---------- -------- --------
OPERATING INCOME 49,056 65,224 161,740 146,778
NONOPERATING INCOME (LOSS) (447) 14,933 (4,931) 20,017
NONOPERATING EXPENSES 2,328 660 6,002 4,305
NONOPERATING INCOME TAX
EXPENSE (CREDIT) (2,451) 4,820 (6,184) 5,084
INTEREST CHARGES 34,096 28,069 63,202 55,457
---------- ---------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGES 14,636 46,608 93,789 101,949
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) - - 77,257 -
---------- ---------- -------- --------
NET INCOME 14,636 46,608 171,046 101,949
PREFERRED STOCK DIVIDEND
REQUIREMENTS 984 503 1,968 1,006
---------- ---------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 13,652 $ 46,105 $169,078 $100,943
========== ========== ======== ========
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 COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------- -----
(in thousands)
JANUARY 1, 2002 $260,458 $715,786 $150,797 $ (340) $1,126,701
Common Stock Dividends (61,968) (61,968)
Preferred Stock Dividends (720) (720)
Capital Stock Expense 285 (285) -
----------
1,064,013
----------
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 232 232
Net Income 101,949 101,949
----------
Total Comprehensive Income 102,181
-------- -------- -------- -------- ----------
JUNE 30, 2002 $260,458 $716,071 $189,773 $ (108) $1,166,194
======== ======== ======== ======== ==========
JANUARY 1, 2003 $260,458 $717,242 $260,439 $(72,082) $1,166,057
Common Stock Dividends (64,133) (64,133)
Preferred Stock Dividends (721) (721)
Capital Stock Expense 1,247 (1,247) -
SFAS 71 Reapplication 162 162
----------
1,101,365
----------
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow Hedges (3,113) (3,113)
Net Income 171,046 171,046
----------
Total Comprehensive Income 167,933
-------- -------- -------- -------- ----------
JUNE 30, 2003 $260,458 $718,651 $365,384 $(75,195) $1,269,298
======== ======== ======== ======== ==========
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,268,852 $2,245,945
Transmission 1,223,020 1,218,108
Distribution 1,977,458 1,951,804
General 276,249 272,901
Construction Work in Progress 241,576 206,545
---------- ----------
Total Electric Utility Plant 5,987,155 5,895,303
Accumulated Depreciation and Amortization 2,348,379 2,424,607
---------- ----------
NET ELECTRIC UTILITY PLANT 3,638,776 3,470,696
---------- ----------
OTHER PROPERTY AND INVESTMENTS 51,733 54,653
---------- ----------
LONG-TERM RISK MANAGEMENT ASSETS 103,273 115,748
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 10,670 4,285
Advances to Affiliates 118,665 -
Accounts Receivable:
Customers 115,387 132,266
Affiliated Companies 77,579 122,665
Miscellaneous 43,165 28,629
Allowance for Uncollectible Accounts (2,454) (13,439)
Fuel Inventory 38,774 53,646
Materials and Supplies 71,793 59,886
Accrued Utility Revenues 2,827 30,948
Risk Management Assets 87,617 94,238
Prepayments and Other 13,896 13,396
---------- ----------
TOTAL CURRENT ASSETS 577,919 526,520
---------- ----------
REGULATORY ASSETS 407,667 395,553
---------- ----------
DEFERRED CHARGES 53,435 64,677
---------- ----------
TOTAL ASSETS $4,832,803 $4,627,847
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $ 260,458 $ 260,458
Paid-in Capital 718,651 717,242
Accumulated Other Comprehensive Income (Loss) (75,195) (72,082)
Retained Earnings 365,384 260,439
---------- ----------
Total Common Shareowner's Equity 1,269,298 1,166,057
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 17,790
Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,822,927 1,738,854
---------- ----------
TOTAL CAPITALIZATION 3,120,875 2,933,561
---------- ----------
OTHER NONCURRENT LIABILITIES 190,988 173,438
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 155,008 155,007
Advances from Affiliates - 39,205
Accounts Payable - General 98,494 141,546
Accounts Payable - Affiliated Companies 61,798 98,374
Taxes Accrued 62,484 29,181
Customer Deposits 39,068 26,186
Interest Accrued 24,692 22,437
Risk Management Liabilities 65,037 69,001
Other 66,729 79,832
---------- ----------
TOTAL CURRENT LIABILITIES 573,310 660,769
---------- ----------
DEFERRED INCOME TAXES 754,648 701,801
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 32,844 33,691
---------- ----------
LONG-TERM RISK MANAGEMENT LIABILITIES 56,692 44,517
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 103,446 80,070
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $4,832,803 $4,627,847
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 171,046 $ 101,949
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes (77,257) -
Depreciation and Amortization 82,073 93,737
Deferred Income Taxes 2,305 (7,055)
Deferred Investment Tax Credits (847) (2,196)
Deferred Power Supply Costs, net 69,528 915
Mark to Market of Risk Management Contracts 19,433 (12,797)
Changes in Certain Assets and Liabilities:
Accounts Receivable, net 36,444 (168,502)
Fuel, Materials and Supplies 2,965 20,384
Accrued Utility Revenues 28,121 7,988
Accounts Payable (79,628) 53,045
Taxes Accrued 33,303 35,244
Interest Accrued 2,255 6,410
Incentive Plan Accrued (9,388) (5,524)
Rate Stabilization Deferral (75,601) -
Change in Other Assets 7,404 (14,767)
Change in Other Liabilities 50,349 12,973
--------- ---------
Net Cash Flows From Operating Activities 262,505 121,804
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (114,806) (128,853)
Proceeds from Sale of Property and Other 1,648 583
--------- ---------
Net Cash Flows Used For Investing Activities (113,158) (128,270)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 500,000 444,110
Change in Advances to/from Affiliates (157,870) (387,315)
Retirement of Long-term Debt (420,238) -
Dividends Paid on Common Stock (64,133) (61,968)
Dividends Paid on Cumulative Preferred Stock (721) (720)
--------- ---------
Net Cash Flows Used For Financing Activities (142,962) (5,893)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 6,385 (12,359)
Cash and Cash Equivalents at Beginning of Period 4,285 13,663
--------- ---------
Cash and Cash Equivalents at End of Period $ 10,670 $ 1,304
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $56,152,000 and
$47,676,000 and for income taxes was $21,102,000 and $36,585,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
Net Income increased $9 million year-to-date including Cumulative Effect of
Accounting Changes of $27 million recorded in the first quarter 2003 (see Note
3). Income Before Cumulative Effect decreased $18 million due to reduced income
from energy trading outside of the AEP territory. Net Income for the quarter
decreased $22 million due to decreased retail sales and lower revenues from
energy trading as a result of cooler weather and a continued sluggish economy.
CSPCo, as a member of the AEP Power Pool, shares in the revenues and costs of
marketing and activities conducted on its behalf by the AEP Power Pool.
Operating Income
Operating Income decreased by $15 million for the quarter and $5 million
year-to-date primarily due to the following:
o Milder weather and a slower-than-expected economic recovery
resulting in decreased retail revenues of $19 million during the
second quarter. Year-to-date retail revenues decreased $10 million
due to a slower-than-expected economic recovery and a mild second
quarter partially offset by favorable colder weather in the first
quarter.
o Fuel for Electric Generation increased $7 million year-to-date, due to
increased generation and higher coal costs.
o Purchased Electricity from AEP Affiliates was $9 million higher in
the quarter and $20 million higher year-to-date due to price and volume
increases along with higher capacity charges.
o Maintenance expense increased $8 million during the quarter and
year-to-date due to scheduled boiler overhaul work and maintenance of
overhead lines.
o Taxes Other Than Income Taxes increased $2 million during the quarter
due to higher property taxes. Taxes Other Than Income Taxes increased
$7 million year-to-date due to higher property taxes and state excise
taxes.
The decrease in Operating Income was partially offset by:
o Increased AEP Power Pool revenues of $9 million ($7 million to
non-affiliated customers and $2 million to affiliated customers)
and $29 million ($19 million to non-affiliated customers and $10
million to affiliated customers) for the quarter and year-to-date
periods, respectively.
o Other Operation expense decreased $9 million during the quarter due to
reduced factoring expense from lower interest rates, reduced post
retirement benefits expense and reduced legal expenses.
o During the quarter, Income Taxes decreased by $7 million due to a
decrease in pre-tax operating book income.
Other Impacts on Earnings
Nonoperating Income, net of expenses and taxes, decreased $8 million for the
quarter and $13 million year-to-date primarily due to the following:
o Net revenues resulting from risk management activities decreased $11
million and $24 million for the quarter and year-to-date, respectively,
as a result of AEP's decision to exit wholesale markets where it does
not own assets.
o Nonoperating Income Tax Expense decreased $3 million and $10 million
for the quarter and year-to-date, respectively, due to a decrease 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 (see
Notes 2 and 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-
In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.
Financing Activities
In February 2003, we issued $250 million of unsecured senior notes due 2013 at a
coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon
of 6.60%. The proceeds from the issuances were used to repay a bank facility,
short-term debt and for other corporate purposes.
In 2003, we redeemed or repaid the following first mortgage bonds:
Coupon or Stated Rate Call Rate Due Date Principal Amounts
--------------------- --------- -------- -----------------
% % (in millions)
- -
6.80 100 2003 $13
6.55 100 2004 26
6.75 100 2004 26
7.75 104.27 2023 33
7.90 103.95 2023 40
8.70 104.35 2022 2
8.55 104.28 2022 15
8.40 104.20 2022 14
8.40 104.20 2022 13
See Note 12 for additional information related to financing activity.
Significant Factors
- -------------------
Federal EPA Complaint and Notice of Violation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", CSPCo, and certain affiliated companies have been
involved in litigation since 1999 regarding generating plant emissions under the
Clean Air Act. Federal EPA and a number of states alleged CSPCo, certain
affiliated companies and eleven unaffiliated utilities made modifications to
generating units at coal-fired generating plants in violation of the Clean Air
Act. Federal EPA filed complaints against us in U.S. District Court for the
Southern District of Ohio. A separate lawsuit initiated by certain special
interest groups was consolidated with the Federal EPA case. The alleged
modification of the generating units occurred 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 Clear Air Act proceedings and
is 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. In the event 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. See Note 7 for
further discussion.
NOx Reductions
Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
under the Clean Air Act requiring substantial reductions in NOx emissions in a
number of eastern states, including certain states in which the AEP System's
generating plants are located. The compliance date for the rules is May 31,
2004.
We are installing non-selective catalytic reduction technology to reduce NOx
emissions on certain units to comply with these rules.
Our estimates indicate that compliance with the rules could result in required
capital expenditures of approximately $87 million. The actual cost to comply
could be significantly different than the estimate depending upon the compliance
alternatives selected to achieve reductions in NOx emissions. Unless any capital
or operating costs for additional pollution control equipment are recovered from
customers, they will have an adverse effect on future results of operations,
cash flows and possibly financial condition. See Note 7 for further discussion.
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the 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.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Domestic Power CSPCo
-------------- -----
(in thousands)
Beginning Balance December 31, 2002 $ 65,117
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (26,884)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 278
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (3,135)
Changes in Fair Value of Risk Management
Contracts (d) 7,390
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (e) -
---------
Total MTM Risk Management Contract Net
Assets 42,766
Net Non-Trading Related Derivative
Contracts (2,096)
--------
Net Fair Value of Risk Management and Derivative
Contracts Ending Balance
June 30, 2003 $ 40,670
========
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior to
2003.
(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 2003. 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 2003.
(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.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $9,129 $10,388 $3,330 $2,954 $ 944 $ - $26,745
Prices Based on Models and Other
Valuation Methods (b) 591 1,307 1,454 2,523 2,551 7,595 16,021
------ ------- ------ ------ ------ ------ -------
Total $9,720 $11,695 $4,784 $5,477 $3,495 $7,595 $42,766
====== ======= ====== ====== ====== ====== =======
(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.
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. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2003
Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (267)
----------------------------------
Changes in Fair Value (a) (1,274)
Reclassifications from OCI to Net
Income (b) 81
-------
Accumulated OCI Derivative Gain (Loss)
June 30, 2003 $(1,460)
=======
(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 OCI 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 Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $993 thousand loss.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
June 30, 2003 December 31, 2002
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$203 $1,384 $771 $203 $867 $2,654 $949 $192
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electric Generation, Transmission and Distribution $ 313,359 $ 326,538 $ 651,796 $ 633,686
Sales to AEP Affiliates 19,712 17,275 40,480 24,953
---------- ---------- ---------- ----------
TOTAL OPERATING REVENUES 333,071 343,813 692,276 658,639
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel for Electric Generation 44,024 43,064 96,067 88,714
Purchased Electricity for Resale 4,012 3,826 8,210 7,555
Purchased Electricity from AEP Affiliates 87,590 78,622 169,739 150,204
Other Operation 52,294 61,788 108,679 115,649
Maintenance 22,612 15,050 37,171 29,190
Depreciation and Amortization 33,299 32,402 67,036 65,138
Taxes Other Than Income Taxes 30,954 29,330 66,562 59,606
Income Taxes 14,869 21,691 40,244 38,995
---------- ---------- ---------- ----------
TOTAL OPERATING EXPENSES 289,654 285,773 593,708 555,051
---------- ---------- ---------- ----------
OPERATING INCOME 43,417 58,040 98,568 103,588
NONOPERATING INCOME (LOSS) 259 9,317 (6,756) 14,391
NONOPERATING EXPENSES (CREDITS) 532 (1,206) 2,394 418
NONOPERATING INCOME TAX EXPENSE (CREDIT) 400 3,450 (5,147) 4,797
INTEREST CHARGES 13,413 13,392 26,875 27,185
---------- ---------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 29,331 51,721 67,690 85,579
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) - - 27,283 -
---------- ---------- ---------- ----------
NET INCOME 29,331 51,721 94,973 85,579
PREFERRED STOCK DIVIDEND REQUIREMENTS (INCLUDING
CAPITAL STOCK EXPENSE) 254 429 508 858
---------- ---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK
$ 29,077 $ 51,292 $ 94,465 $ 84,721
========== ========== ========== ==========
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 COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ------------- -----
(in thousands)
JANUARY 1, 2002 $41,026 $574,369 $176,103 $ - $791,498
Common Stock Dividends Declared (43,534) (43,534)
Preferred Stock Dividends Declared (350) (350)
Capital Stock Expense 508 (508) -
--------
747,614
--------
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Power Hedges 1,449 1,449
Net Income 85,579 85,579
--------
Total Comprehensive Income 87,028
------- -------- -------- -------- --------
JUNE 30, 2002 $41,026 $574,877 $217,290 $ 1,449 $834,642
======= ======== ======== ======== ========
JANUARY 1, 2003 $41,026 $575,384 $290,611 $(59,357) $847,664
Common Stock Dividends Declared (86,622) (86,622)
Capital Stock Expense 508 (508) -
--------
761,042
--------
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (1,193) (1,193)
Net Income 94,973 94,973
--------
Total Comprehensive Income 93,780
------- -------- -------- -------- --------
JUNE 30, 2003 $41,026 $575,892 $298,454 $(60,550) $854,822
======= ======== ======== ======== ========
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,592,165 $1,582,627
Transmission 415,067 413,286
Distribution 1,230,377 1,208,255
General 155,721 165,025
Construction Work in Progress 119,049 98,433
---------- ----------
Total Electric Utility Plant 3,512,379 3,467,626
Accumulated Depreciation and Amortization 1,448,956 1,465,174
---------- ----------
NET ELECTRIC UTILITY PLANT 2,063,423 2,002,452
---------- ----------
OTHER PROPERTY AND INVESTMENTS 33,293 35,759
---------- ----------
LONG-TERM RISK MANAGEMENT ASSETS 60,705 77,810
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 7,485 1,479
Advances to Affiliates, net - 31,257
Accounts Receivable:
Customers 37,191 49,566
Affiliated Companies 40,659 54,518
Miscellaneous 20,112 22,005
Allowance for Uncollectible Accounts (609) (634)
Fuel 17,162 24,844
Materials and Supplies 47,016 40,339
Accrued Utility Revenues 6,436 12,671
Risk Management Assets 51,519 63,348
Prepayments and Other 8,944 7,308
---------- ----------
TOTAL CURRENT ASSETS 235,915 306,701
---------- ----------
REGULATORY ASSETS 252,591 257,682
---------- ----------
DEFERRED CHARGES 50,785 72,836
---------- ----------
TOTAL ASSETS $2,696,712 $2,753,240
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 575,892 575,384
Accumulated Other Comprehensive Income (Loss) (60,550) (59,357)
Retained Earnings 298,454 290,611
---------- ----------
Total Common Shareholder's Equity 854,822 847,664
Long-term Debt 747,736 418,626
Long-term Debt - Affiliated Companies - 160,000
---------- ----------
TOTAL CAPITALIZATION 1,602,558 1,426,290
---------- ----------
OTHER NONCURRENT LIABILITIES 90,243 95,460
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 30,000 43,000
Short-term Debt - Affiliates - 290,000
Advances from Affiliates, net 115,014 -
Accounts Payable - General 57,710 89,736
Accounts Payable - Affiliated 74,299 81,599
Taxes Accrued 87,376 112,172
Interest Accrued 17,467 9,798
Risk Management Liabilities 38,230 46,375
Other 49,942 36,790
---------- ----------
TOTAL CURRENT LIABILITIES 470,038 709,470
---------- ----------
DEFERRED INCOME TAXES 451,884 437,771
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 32,381 33,907
---------- ----------
LONG-TERM RISK MANAGEMENT LIABILITIES 33,324 29,926
---------- ----------
DEFERRED CREDITS AND REGULATORY LIABILITIES 16,284 20,416
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $2,696,712 $2,753,240
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
OPERATING ACTIVITIES: (in thousands)
Net Income $ 94,973 $ 85,579
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes (27,283) -
Depreciation and Amortization 67,036 65,192
Deferred Income Taxes (3,135) (5,432)
Deferred Investment Tax Credits (1,526) (1,557)
Mark-to-Market of Risk Management Contracts 19,215 (11,260)
Changes in Certain Assets and Liabilities:
Accounts Receivable, net 28,102 (102,607)
Fuel, Materials and Supplies 1,005 (2,577)
Accrued Utility Revenues 6,235 (10,289)
Prepayments and Other Current Assets (1,636) (9,186)
Accounts Payable (39,326) 48,171
Taxes Accrued (24,796) (33,183)
Interest Accrued 7,669 89
Deferred Property Tax 30,973 23,971
Change in Other Assets (11,697) (7,865)
Change in Other Liabilities (1,650) 3,440
-------- --------
Net Cash Flows From Operating Activities 144,159 42,486
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures (65,492) (55,842)
Proceeds from Sale of Property 190 389
-------- --------
Net Cash Flows Used For Investing Activities (65,302) (55,453)
-------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 500,000 -
Change in Advances to/from Affiliates, net 146,271 (202,093)
Retirement of Long-term Debt (182,500) -
Change in Short-term Debt - Affiliates (290,000) 250,000
Retirement of Long-term Debt - Affiliated Companies (160,000) -
Dividends Paid on Common Stock (86,622) (43,534)
Dividends Paid on Cumulative Preferred Stock - (350)
-------- --------
Net Cash Flows From (Used For) Financing Activities (72,851) 4,023
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 6,006 (8,944)
Cash and Cash Equivalents at Beginning of Period 1,479 12,358
-------- --------
Cash and Cash Equivalents at End of Period $ 7,485 $ 3,414
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $18,442,000 and
$26,262,000 and for income taxes was $9,245,000 and $32,254,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
In the second quarter of 2003, Net Income decreased $9 million reflecting mild
spring weather, higher fuel and purchased power costs, a weak economy and the
impact of plant availability. Net Income increased $8 million including an
unfavorable $3 million Cumulative Effect of Accounting Change in the first six
months of 2003 (see Note 3). Net Income (Loss) Before Cumulative Effect of
Accounting Change increased $11 million due to an improvement in earnings from
retail and AEP Power Pool sales resulting from the interactions of plant
availability, colder winter weather and higher margins partially offset by the
weak economy. We, as a member of the AEP Power Pool, share in the revenues and
costs of marketing and activities conducted on our behalf by the AEP Power Pool.
During the second quarter of 2003, both units of Cook Plant were unavailable due
to a forced outage which impacted operating income significantly. See
significant factors below.
Operating Income
Operating Income decreased by less than $1 million in the second quarter
primarily due to the following:
o Increased Fuel for Electric Generation expense of $13 million reflecting
an increase in the average cost of fuel.
o Increased Purchased Electricity from AEP Affiliates of $10 million due to
purchasing replacement power during outages at both units of Cook Plant.
o A $7 million decrease in Electric Generation, Transmission and Distribution
revenues due to milder weather during the second quarter of 2003.
The decrease in Operating Income during the second quarter was partially offset
by:
o Sales to AEP Affiliates increased by $15 million due to increased capacity
revenue and increased sales volume to the AEP Power Pool and western
affiliates.
o A decline in Other Operation expense of $13 million due to the favorable
effect of cost reduction efforts instituted in the fourth quarter of 2002.
o A $6 million decrease in Taxes Other Than Income Taxes due to a favorable
tax law change in Indiana effective March 2002 and a lower estimate for
Cook Plant's assessed value which reduced real and personal property tax
estimates on which 2003 accruals are based.
Operating Income increased by $28 million year-to-date primarily due to the
following:
o Electric Generation, Transmission and Distribution revenues increased
$38 million due to an increase in sales reflecting a colder winter.
o Sales to AEP Affiliates increased by $37 million due to more power
being available for sale in 2003 and our share of sales to our
western affiliates. In the first quarter of 2002, one unit of Cook
plant was shut down for refueling and both Rockport units were
down for planned boiler maintenance.
o A decline in Other Operation expense of $22 million due to the impact of
cost reduction efforts instituted in the fourth quarter of 2002 and
having two refueling outages in 2002 verses one refueling outage in 2003.
o A $7 million decrease in Taxes Other Than Income Taxes reflects a
favorable tax law change in Indiana effective March 2002 and a lower
estimate for Cook Plant's assessed value which reduced real and personal
property tax estimates on which 2003 accruals are based.
The year-to-date increase in Operating Income was partially offset by:
o Increased Fuel for Electric Generation expense of $32 million reflecting
an increase in the average cost of fuel and increased generation.
o Increased Purchased Electricity from AEP Affiliates of $23 million
due to higher power purchases from AEGCo in 2003 compared to 2002 when
outages at both units of the Rockport Plant decreased available power and
purchases of replacement power during the 2003 Cook outages.
o Increased Income Taxes of $13 million reflecting an increase in pre-tax
income.
Other Impacts on Earnings
Nonoperating Income decreased $8 million in the second quarter and $22 million
year-to-date primarily due to lower margins for power sold outside of AEP's
traditional marketing area reflecting reduced demand and AEP's plan to exit
those risk management activities in areas outside of its traditional market
area.
Interest Charges decreased $2 million in the second quarter primarily due to a
reduction in outstanding long-term debt of $255 million retired in May 2003.
Cumulative Effect of Accounting Change
The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 (see Note 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 Baa1 BBB BBB+
Senior Unsecured Debt Baa2 BBB BBB
During the first quarter of 2003, Moody's Investors Service (Moody's), Standard
& Poors (S&P) and Fitch Rating Service completed their reviews of AEP and its
rated subsidiaries. The reviews resulted in downgrades of debt ratings. The
completion of these reviews was a culmination of ratings action started during
2002.
Cash Flow
Cash flows for six months ended June 30, 2003 and 2002 were as follows:
2003 2002
-------------- --------------
(in thousands)
Cash and cash equivalents at beginning of period $ 3,237 $ 16,804
-------- --------
Cash flow from (used for):
Operating activities 88,838 9,204
Investing activities (70,831) (67,396)
Financing activities (15,513) 55,096
-------- --------
Net increase (decrease) in cash and cash equivalents 2,494 (3,096)
-------- --------
Cash and cash equivalents at end of period $ 5,731 $ 13,708
======== ========
Operating Activities
Operating activities during the first half of 2003 provided $80 million more
cash than during the first half of 2002 largely due to the year-over-year
increase in net income of $8 million and decreases in various Regulatory Assets.
Investing Activities
Cash flows used for investing activities during the first half of 2003 were $71
million compared to $67 million during the first half of 2002. The primary
reason for the year-over-year variance was a construction expenditures increase
of $4 million.
Financing Activities
Financing activities in the first half of 2003 used $71 million more than in the
first half of 2002 primarily due to:
o Retirement and restructuring of our short-term and long-term debt during 2003.
We retired $255 million of long-term debt using short-term debt.
o Dividends paid on common stock of $20 million. Common dividends were not
distributed in 2002.
Financing Activity
In May 2003, we retired $255 million of long-term debt prior to maturity using
short-term debt as shown in the following table:
Coupon
Type of Or Stated Call Principal
Debt Rate Rate Due Date Amounts
---- ----- ---- -------- -------
% % (in millions)
- -
First Mortgage Bonds 8.50 100 2022 $75
First Mortgage Bonds 7.35 100 2023 15
Junior Debentures 8.00 100 2026 40
Junior Debentures 7.60 100 2038 125
See Note 12 for additional information related to financing activity.
Significant Factors
- -------------------
Nuclear Plant Outages
In April 2003, both units of Cook Plant were taken offline due to an influx of
fish in the plant's cooling water system which caused a reduction in cooling
water to essential plant equipment. After repair of damage caused by the fish
intrusion, Cook Plant Unit 1 returned to service in May 2003 and Unit 2 returned
to service in June 2003 following completion of a scheduled refueling outage.
Federal EPA Complaint and Notice of Violation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", we have been involved in litigation since 1999
regarding generating plant emissions under the Clean Air Act. Federal EPA and a
number of states alleged I&M, certain affiliated companies and eleven
unaffiliated utilities made modifications to generating units at coal-fired
generating plants in violation of the Clean Air Act. Federal EPA filed
complaints against us in U.S. District Court for the Southern District of Ohio.
A separate lawsuit initiated by certain special interest groups was consolidated
with the Federal EPA case. The alleged modification of the generating units
occurred 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 Clear Air Act proceedings and
is 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. In the event 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. See Note 7 for
further discussion.
NOx Reductions
Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
under the Clean Air Act requiring substantial reductions in NOx emissions in a
number of eastern states, including certain states in which the AEP System's
generating plants are located. The compliance date for the rules is May 31,
2004.
We are installing non-selective catalytic reduction technology to reduce NOx
emissions on certain units to comply with these rules. Our estimates indicate
that compliance with the rules could result in required capital expenditures of
approximately $39 million. The actual cost to comply could be significantly
different than the estimate depending upon the compliance alternatives selected
to achieve reductions in NOx emissions. Unless any capital or operating costs
for additional pollution control equipment are recovered from customers, they
will have an adverse effect on future results of operations, cash flows and
possibly financial condition. See Note 7 for further discussion.
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the 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.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Domestic Power
- --------------
(in thousands)
Beginning Balance December 31, 2002 $ 70,861
- -----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (25,361)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 298
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (4,861)
Changes in Fair Value of Risk Management
Contracts (d) 5,264
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (e) 326
--------
Total MTM Risk Management Contract Net
Assets 46,527
Net Non-Trading Related Derivative
Contracts (2,241)
--------
Net Fair Value of Risk Management and Derivative
Contracts June 30, 2003 $ 44,286
========
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior to
2003.
(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 2003. 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 2003.
(d)"Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather, etc.
(e)"Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Operations. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $10,556 $11,146 $3,564 $3,161 $1,010 $ - $29,437
Prices Based on Models and Other
Valuation Methods (b) 609 1,369 1,556 2,700 2,730 8,126 17,090
------- ------- ------ ------ ------ ------ -------
Total $11,165 $12,515 $5,120 $5,861 $3,740 $8,126 $46,527
======= ======= ====== ====== ====== ====== =======
(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" 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.
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. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2003
Domestic
Power
-----
(in thousands)
Accumulated OCI, December 31, 2002 $ (286)
----------------------------------
Changes in Fair Value (a) (1,363)
Reclassifications from OCI to Net
Income (b) 87
-------
Accumulated OCI Derivative Gain (Loss)
June 30, 2003 $(1,562)
=======
(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 OCI 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 Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $1,063 thousand loss.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
June 30, 2003 December 31, 2002
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$218 $1,481 $825 $218 $927 $2,840 $1,016 $206
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electric Generation, Transmission and Distribution $316,506 $323,642 $666,293 $628,668
Sales to AEP Affiliates 60,400 45,401 129,211 92,610
-------- -------- -------- --------
TOTAL OPERATING REVENUES 376,906 369,043 795,504 721,278
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel for Electric Generation 65,763 53,163 138,857 107,319
Purchased Electricity for Resale 7,035 4,551 13,317 10,680
Purchased Electricity from AEP Affiliates 73,353 63,110 139,251 116,617
Other Operation 108,532 121,180 209,913 232,099
Maintenance 42,595 39,580 73,962 70,623
Depreciation and Amortization 42,841 41,870 86,567 83,736
Taxes Other Than Income Taxes 12,149 17,855 28,970 36,096
Income Taxes 5,409 7,869 26,448 13,880
-------- -------- -------- --------
TOTAL OPERATING EXPENSES 357,677 349,178 717,285 671,050
-------- -------- -------- --------
OPERATING INCOME 19,229 19,865 78,219 50,228
NONOPERATING INCOME 13,286 21,549 16,905 38,553
NONOPERATING EXPENSES 12,900 9,100 25,835 22,410
NONOPERATING INCOME TAX EXPENSE
(CREDIT) (849) 1,313 (5,300) 888
INTEREST CHARGES 21,655 23,507 45,093 46,931
-------- -------- -------- --------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE (1,191) 7,494 29,496 18,552
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) - - (3,160) -
-------- -------- -------- --------
NET INCOME (LOSS) (1,191) 7,494 26,336 18,552
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,123 1,153 2,272 2,308
-------- -------- -------- --------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ (2,314) $ 6,341 $ 24,064 $ 16,244
======== ======== ======== ========
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 COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ------------- -----
(in thousands)
JANUARY 1, 2002 $56,584 $733,216 $ 74,605 $(3,835) $ 860,570
Preferred Stock Dividends (2,243) (2,243)
Capital Stock Expense 275 (67) 208
----------
858,535
----------
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Cash Flow Interest Rate Hedge 2,487 2,487
Unrealized Gain on Cash Flow Power Hedges 1,567 1,567
Net Income 18,552 18,552
----------
Total Comprehensive Income 22,606
------- -------- -------- ------- ----------
JUNE 30, 2002 $56,584 $733,491 $ 90,847 $ 219 $ 881,141
======= ======== ======== ======= ==========
JANUARY 1, 2003 $56,584 $858,560 $143,996 $(40,487) $1,018,653
Common Stock Dividends (20,000) (20,000)
Preferred Stock Dividends (2,205) (2,205)
Capital Stock Expense 67 (67) -
----------
996,448
----------
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (1,276) (1,276)
Net Income 26,336 26,336
----------
Total Comprehensive Income 25,060
------- -------- -------- -------- ----------
JUNE 30, 2003 $56,584 $858,627 $148,060 $(41,763) $1,021,508
======= ======== ======== ======== ==========
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,866,216 $2,768,463
Transmission 977,471 971,599
Distribution 938,692 921,835
General (including nuclear fuel) 237,046 220,137
Construction Work in Progress 168,824 147,924
---------- ----------
Total Electric Utility Plant 5,188,249 5,029,958
Accumulated Depreciation and Amortization 2,681,293 2,568,604
---------- ----------
NET ELECTRIC UTILITY PLANT 2,506,956 2,461,354
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS 937,854 870,754
---------- ----------
LONG-TERM RISK MANAGEMENT ASSETS 65,110 83,265
---------- ----------
OTHER PROPERTY AND INVESTMENTS 114,019 120,941
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 5,731 3,237
Advances to Affiliates - 191,226
Accounts Receivable:
Customers 57,150 67,333
Affiliated Companies 73,760 122,489
Miscellaneous 22,978 30,468
Allowance for Uncollectible Accounts (567) (578)
Fuel 23,255 32,731
Materials and Supplies 103,429 95,552
Risk Management Assets 55,993 68,148
Prepayments and Other 10,148 18,410
---------- ----------
TOTAL CURRENT ASSETS 351,877 629,016
---------- ----------
REGULATORY ASSETS 295,492 348,212
---------- ----------
DEFERRED CHARGES 70,420 73,649
---------- ----------
TOTAL ASSETS $4,341,728 $4,587,191
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 858,627 858,560
Accumulated Other Comprehensive Income (Loss) (41,763) (40,487)
Retained Earnings 148,060 143,996
---------- ----------
Total Common Shareowner's Equity 1,021,508 1,018,653
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,101 8,101
Subject to Mandatory Redemption 63,445 64,945
Long-term Debt 1,337,586 1,587,062
---------- ----------
TOTAL CAPITALIZATION 2,430,640 2,678,761
---------- ----------
OTHER NONCURRENT LIABILITIES:
Asset Retirement Obligations 534,321 -
Nuclear Decommissioning - 620,672
Other 129,155 138,965
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES 663,476 759,637
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 30,000 30,000
Advances from Affiliates 71,966 -
Accounts Payable:
General 72,073 125,048
Affiliated Companies 39,365 93,608
Taxes Accrued 52,358 71,559
Interest Accrued 19,664 21,481
Risk Management Liabilities 41,007 48,568
Other 89,233 101,051
---------- ----------
TOTAL CURRENT LIABILITIES 415,666 491,315
---------- ----------
DEFERRED INCOME TAXES 327,745 356,197
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 94,039 97,709
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 72,032 73,885
---------- ----------
LONG-TERM RISK MANAGEMENT LIABILITIES 35,810 32,261
---------- ----------
DEFERRED CREDITS AND REGULATORY LIABILITIES 302,320 97,426
---------- ----------
CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $4,341,728 $4,587,191
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 26,336 $ 18,552
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change 3,160 -
Depreciation and Amortization 86,567 83,779
Deferral of Incremental Nuclear Refueling Outage Expenses, net (8,799) (45,701)
Unrecovered Fuel and Purchased Power Costs 18,751 18,751
Amortization of Nuclear Outage Costs 20,000 20,000
Deferred Income Taxes (10,252) (7,723)
Deferred Investment Tax Credits (3,670) (3,689)
Mark-to-Market of Risk Management Contracts 19,474 2,377
Changes in Certain Assets and Liabilities:
Accounts Receivable, net 66,391 (189,078)
Fuel, Materials and Supplies 1,599 189
Accounts Payable (107,218) 134,183
Taxes Accrued (19,201) (1,713)
Change in Other Assets (51,976) (33,363)
Change in Other Liabilities 47,676 12,640
--------- ---------
Net Cash Flows From Operating Activities 88,838 9,204
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (71,246) (67,396)
Other 415 -
--------- ---------
Net Cash Flows Used For Investing Activities (70,831) (67,396)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 49,648
Retirement of Cumulative Preferred Stock (1,500) (424)
Retirement of Long-term Debt (255,000) (50,000)
Change in Advances to/from Affiliates, net 263,192 58,115
Dividends Paid on Common Stock (20,000) -
Dividends Paid on Cumulative Preferred Stock (2,205) (2,243)
--------- ---------
Net Cash Flows From (Used For) Financing Activities (15,513) 55,096
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 2,494 (3,096)
Cash and Cash Equivalents at Beginning of Period 3,237 16,804
--------- ---------
Cash and Cash Equivalents at End of Period $ 5,731 $ 13,708
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $44,812,000 and
$42,695,000 and for income taxes was $50,731,000 and $18,711,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
Net Income for the second quarter and first half of 2003 decreased $1 million
and $2 million, respectively, from the corresponding periods of the prior year.
Net Income for the first half of 2003 included a loss from Cumulative Effect of
Accounting Change of $1 million (see Note 3). The declines from the prior
periods are primarily due to reduced gains from risk management activities
compared to the prior year partially offset by an improvement in earnings from
AEP Power Pool sales. We, as a member of the AEP Power Pool, share in the
revenues and costs of marketing and activities conducted on our behalf by the
AEP Power Pool.
Operating Income
Operating Income for the second quarter and six months ended June 30, 2003
increased $1 million and $6 million, respectively, primarily due to:
o An increase in system sales of $5 million for the quarter and $12 million
year-to-date.
o A decrease in the current quarter in Maintenance expense of $1 million due
to significant boiler overhaul work performed in the second quarter of 2002.
o A decrease in Other Operation expense of $1 million from second quarter
2002 due to lower employee benefits expense and decreased engineering
expenses.
o An increase in residential sales for the six-month period of $2 million
reflecting increased first quarter 2003 demand resulting from more severe
winter weather in 2003.
The increases in Operating Income were partially offset by:
o A decline in retail sales of $2 million in the second quarter of 2003
due to decreased residential sales reflecting the mild weather conditions
and decreased industrial sales reflecting the slower-than-expected economic
recovery.
o Increases in Purchased Electricity from AEP Affiliates of $4 million and
$12 million for the quarter and year-to-date, respectively, necessary to
support sales during the Big Sandy plant outage for the NOx reduction
upgrades. In addition, purchases increased from the Rockport Plant 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.
o An increase for the six months ended June 30, 2003 in Maintenance expense
of $1 million primarily due to distribution line maintenance resulting
from a major ice storm in February 2003.
o Increased Income Taxes of $1 million and $3 million for the quarter and
year-to-date, respectively, due to increases in pre-tax operating book
income for both periods.
Other Impacts on Earnings
Nonoperating Income for the second quarter and first half of 2003 decreased $4
million and $8 million, respectively, primarily due to reduced gains from risk
management activities compared to the prior year. The decreases for the quarter
and six months in Nonoperating Income Tax Expense were a result of the decreases
in Nonoperating Income.
Cumulative Effect of Accounting Change
The Cumulative Effect of Accounting Change is due to the implementation of EITF
02-3 (see Note 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 Baa1 BBB BBB+
Senior Unsecured Debt Baa2 BBB BBB
In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002.
Financing Activity
In June 2003, we issued $75 million in Senior Unsecured Notes due 2032. The
proceeds were used to retire $40 million of Junior Subordinated Debentures
(JSD), a $15 million Note Payable to AEP and to finance construction activities.
In April 2003, we called the following JSD for early redemption on May 30, 2003:
Coupon
Or Stated Call Principal
Rate Rate Due Date Amounts
----- ---- -------- -------
% % (in millions)
- -
8.72 100 2025 $40
See Note 12 for additional information related to financing activity.
Significant Factors
- -------------------
NOx Reductions
Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
under the Clean Air Act requiring substantial reductions in NOx emissions in a
number of eastern states, including Kentucky where our generating plant is
located. The compliance date for the rules is May 31, 2004.
In May 2003, selective catalytic reduction (SCR) technology and non-SCR
technology to reduce NOx emissions at our Big Sandy plant commenced operation to
comply with these rules.
The capital expenditures for the SCR and non-SCR technology totaled $177 million
through June 30, 2003. In 2003, the KPSC granted recovery of approximately $18
million annually (see Note 5). See Note 7 for further discussion of emissions
control technology.
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the 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.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Domestic Power
--------------
(in thousands)
Beginning Balance December 31, 2002 $24,998
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (8,989)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 108
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (1,744)
Changes in Fair Value of Risk Management
Contracts (d) 1,833
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (e) 351
------
Total MTM Risk Management Contract Net
Assets 16,557
Net Non-Trading Related Derivative
Contracts (810)
------
Net Fair Value of Risk Management and Derivative
Contracts June 30, 2003 $15,747
=======
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior
to 2003.
(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 2003. 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 2003.
(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.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $3,535 $4,021 $1,289 $1,144 $ 365 $ - $10,354
Prices Based on Models and Other
Valuation Methods (b) 229 506 563 977 988 2,940 6,203
------ ------ ------ ------ ------ ------ -------
Total $3,764 $4,527 $1,852 $2,121 $1,353 $2,940 $16,557
====== ====== ====== ====== ====== ====== =======
(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.
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. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2003
Domestic
Power Interest Rate Consolidated
-------- ------------- ------------
(in thousands)
Accumulated OCI, December 31, 2002 $(103) $425 $ 322
----------------------------------
Changes in Fair Value (a) (493) (1) (494)
Reclassifications from OCI to Net
Income (b) 31 (43) (12)
----- ---- -------
Accumulated OCI Derivative Gain (Loss)
June 30, 2003 $(565) $381 $(184)
===== ==== =====
(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 OCI 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 Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $298 thousand loss.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
June 30, 2003 December 31, 2002
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$79 $536 $298 $79 $333 $1,019 $364 $74
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electric Generation, Transmission and Distribution $ 84,296 $ 83,271 $188,255 $176,434
Sales to AEP Affiliates 11,168 8,893 19,303 14,915
-------- -------- -------- --------
TOTAL OPERATING REVENUES 95,464 92,164 207,558 191,349
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel for Electric Generation 15,439 17,570 33,386 39,337
Purchased Electricity from AEP Affiliates 36,152 32,368 73,547 61,309
Other Operation 11,695 12,619 23,832 24,970
Maintenance 7,161 8,078 13,926 12,627
Depreciation and Amortization 9,248 8,269 17,960 16,526
Taxes Other Than Income Taxes 2,077 2,368 4,442 4,503
Income Taxes 2,728 1,342 9,667 7,043
-------- -------- -------- --------
TOTAL OPERATING EXPENSES 84,500 82,614 176,760 166,315
-------- -------- -------- --------
OPERATING INCOME 10,964 9,550 30,798 25,034
NONOPERATING INCOME (LOSS) (550) 3,553 (2,965) 5,195
NONOPERATING EXPENSES (CREDITS) 110 (576) 342 (6)
NONOPERATING INCOME TAX
EXPENSE (CREDIT) (926) 1,920 (1,484) 1,730
INTEREST CHARGES 7,135 6,513 13,859 13,013
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE 4,095 5,246 15,116 15,492
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) - - (1,134) -
-------- -------- -------- --------
NET INCOME $ 4,095 $ 5,246 $ 13,982 $ 15,492
======== ======== ======== ========
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 COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
(in thousands)
JANUARY 1, 2002 $50,450 $158,750 $48,833 $(1,903) $256,130
Common Stock Dividends (14,088) (14,088)
--------
242,042
--------
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 1,445 1,445
Net Income 15,492 15,492
--------
Total Comprehensive Income 16,937
------- -------- ------- ------- --------
JUNE 30, 2002 $50,450 $158,750 $50,237 $ (458) $258,979
======= ======== ======= ======= ========
JANUARY 1, 2003 $50,450 $208,750 $48,269 $(9,451) $298,018
Common Stock Dividends (10,966) (10,966)
--------
287,052
--------
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow Hedges (506) (506)
Net Income 13,982 13,982
--------
Total Comprehensive Income 13,476
------- -------- ------- ------- --------
JUNE 30, 2003 $50,450 $208,750 $51,285 $ (9,957) $300,528
======= ======== ======= ======== ========
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 415,289 $ 275,121
Transmission 376,119 373,639
Distribution 419,272 414,281
General 66,532 67,449
Construction Work in Progress 60,128 165,129
---------- ----------
Total Electric Utility Plant 1,337,340 1,295,619
Accumulated Depreciation and Amortization 397,743 397,304
---------- ----------
NET ELECTRIC UTILITY PLANT 939,597 898,315
---------- ----------
OTHER PROPERTY AND INVESTMENTS 6,333 6,904
---------- ----------
LONG-TERM RISK MANAGEMENT ASSETS 23,502 29,871
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 1,692 2,304
Accounts Receivable:
Customers 16,672 22,044
Affiliated Companies 14,730 23,802
Miscellaneous 4,916 2,889
Allowance for Uncollectible Accounts (974) (192)
Fuel 11,538 10,817
Materials and Supplies 18,078 16,127
Accrued Utility Revenues 6,435 5,301
Accrued Tax Benefit - 1,253
Risk Management Assets 19,946 24,320
Prepayments and Other 2,954 2,127
---------- ----------
TOTAL CURRENT ASSETS 95,987 110,792
---------- ----------
REGULATORY ASSETS 104,763 101,976
---------- ----------
DEFERRED CHARGES 14,494 16,818
---------- ----------
TOTAL ASSETS $1,184,676 $1,164,676
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
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
Accumulated Other Comprehensive Income (Loss) (9,957) (9,451)
Retained Earnings 51,285 48,269
---------- ----------
Total Common Shareowner's Equity 300,528 298,018
Long-term Debt 427,555 391,632
Long-term Debt - Affiliated Companies 60,000 60,000
---------- ----------
TOTAL CAPITALIZATION 788,083 749,650
---------- ----------
OTHER NONCURRENT LIABILITIES 25,794 27,319
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year
- Affiliated Companies - 15,000
Advances from Affiliates 54,262 23,386
Accounts Payable:
General 25,083 46,515
Affiliated Companies 22,216 44,035
Customer Deposits 11,219 8,048
Interest Accrued 6,554 6,471
Taxes Accrued 4,922 -
Risk Management Liabilities 14,800 17,803
Other 10,173 14,322
---------- ----------
TOTAL CURRENT LIABILITIES 149,229 175,580
---------- ----------
DEFERRED INCOME TAXES 187,745 178,313
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 8,578 9,165
---------- ----------
LONG-TERM RISK MANAGEMENT LIABILITIES 12,901 11,488
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 12,346 13,161
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $1,184,676 $1,164,676
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 13,982 $ 15,492
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change 1,134 -
Depreciation and Amortization 17,960 16,526
Deferred Income Taxes 7,605 965
Deferred Investment Tax Credits (587) (591)
Deferred Fuel Costs, net (932) 2,430
Mark-to-Market of Risk Management Contracts 6,697 (4,479)
Changes in Certain Assets and Liabilities:
Accounts Receivable, net 13,199 (27,044)
Fuel, Materials and Supplies (2,672) (6,481)
Accrued Utility Revenues (1,134) (2,418)
Accounts Payable (43,251) 24,610
Taxes Accrued 6,175 129
Change in Other Assets (2,360) (1,416)
Change in Other Liabilities 1,261 6,355
-------- --------
Net Cash Flows From Operating Activities 17,077 24,078
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures (57,897) (51,997)
Proceeds from Sales of Property and Other 298 -
-------- --------
Net Cash Flow Used for Investing Activities (57,599) (51,997)
-------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 75,000 -
Issuance of Long-term Debt - Affiliated Companies - 123,843
Retirement of Long-term Debt (40,000) (14,500)
Retirement of Long-term Debt - Affiliated Companies (15,000) -
Change in Advances to/from Affiliates, net 30,876 (68,365)
Dividends Paid (10,966) (14,088)
-------- --------
Net Cash Flows From Financing Activities 39,910 26,890
-------- --------
Net Decrease in Cash and Cash Equivalents (612) (1,029)
Cash and Cash Equivalents at Beginning of Period 2,304 1,947
-------- --------
Cash and Cash Equivalents at End of Period $ 1,692 $ 918
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $13,245,000 and
$13,692,000 in 2003 and 2002, respectively. Cash paid (received) for income
taxes was $(5,537,000) and $7,024,000 in 2003 and 2002, respectively. Noncash
acquisitions under capital leases were $22,000 in 2002.
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
Net Income increased $130 million year-to-date including a $125 million
Cumulative Effect of Accounting Changes in the first quarter of 2003 (see Note
3). Net Income Before Cumulative Effect of Accounting Changes increased $5
million year-to-date due primarily to increased Sales to AEP Affiliates. We, as
a member of the AEP Power Pool, share in the revenues and the costs of the AEP
Power Pool's wholesale sales to neighboring utilities and power marketing
transactions.
Operating Income
Operating Income increased $19 million for the second quarter and $34 million
year-to-date primarily due to the following:
o Second quarter and year-to-date revenues from non-affiliated
system sales increased $9 million and $26 million, respectively,
while affiliated system sales increased $25 million and $42
million, respectively. The overall increase in system sales for
resale is the result of optimizing our generation capacity and
selling our excess generated power due to the unexpected outages
at the affiliate owned Cook Plant.
o Other Operation expenses decreased $21 million for the second
quarter and $19 million year-to-date primarily due to a $7 million
pre-tax adjustment to the workers' compensation reserve related to
the sale of coal companies coupled with reductions in employee
salary and benefit expenses and office related expenses totaling
$12 million.
The increase in Operating Income was partially offset by:
o Second quarter retail revenues decreased $15 million due to milder weather
during the second quarter 2003 and the effects of a weak economy.
o Year-to-date Fuel for Electric Generation expense increased $16 million
due to an increase of 7.7% in MWHs generated.
o Second quarter and year-to-date expenses for Purchased Electricity from
AEP Affiliates were $4 million and $13 million higher due to price and
volume increases.
o Second quarter and year-to-date Maintenance expenses increased $24 million
and $30 million primarily due to increased boiler overhaul costs coupled
with increased expense in maintaining overhead lines due to storm damage
in southern Ohio.
Other Impacts on Earnings
Nonoperating Income decreased $14 million in the second quarter and $31 million
year-to-date primarily due to lower margins for power sold outside of AEP's
traditional marketing area reflecting reduced demand and AEP's plan to exit risk
management activities in areas outside of its traditional market area.
Nonoperating Expenses increased $3 million for the second quarter and $6 million
year-to-date as a result of an increase in expenses related to the Cook Coal
Terminal in both the quarter-to-date and year-to-date periods and a $2 million
loss recorded on the sale of our water heater rental program in the year-to-date
period.
The $7 million year-to-date decrease in Nonoperating Income Tax Expense was the
result of the overall decrease in income related to our risk management
activities.
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 (see
Notes 2 and 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+
In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.
Cash Flow
Cash flows for six months ended June 30, 2003 and 2002 were as follows:
2003 2002
-------------- --------------
(in thousands)
Cash and cash equivalents at beginning of period $ 5,285 $ 8,848
Cash flow from (used for):
Operating activities 74,842 239,758
Investing activities (114,485) (157,797)
Financing activities 43,033 (83,937)
--------- ---------
Net increase (decrease) in cash and cash equivalents 3,390 (1,976)
--------- ---------
Cash and cash equivalents at end of period $ 8,675 $ 6,872
========= =========
Operating Activities
Cash flow from operating activities during the first half of 2003 decreased $165
million as they were adversely impacted primarily by significant reductions of
accounts payable balances partially associated with a wind down of risk
management activities in the current year.
Investing Activities
Cash flows used for investing activities were reduced in the current year
directly attributable to a $40 million decrease in construction expenditures.
Financing Activities
Cash flow from financing activities in the first of half of 2003 used $127
million less than the first half of 2002 primarily due to:
o Retirement and restructuring of our long-term and short-term debt
during 2003. We retired $300 million of Long-term Debt to Affiliated
Companies and $275 million of Short-term Debt to Affiliated Companies with
the proceeds of two Senior Unsecured Notes at $250 million each, as well
as a $232 million increase in Advances from Affiliates.
o Dividends paid on common stock increased $19 million from the prior period.
Financing Activity
In February 2003, we issued $250 million of unsecured senior notes due 2013 at a
coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon
of 6.60%. The proceeds from the issuances were used to repay long-term debt,
short-term debt and for other corporate purposes.
In July 2003, we issued $225 million of unsecured senior notes due 2014 at a
coupon of 4.85% and $225 million of unsecured senior notes due 2033 at a coupon
of 6.375%. See Note 12 for additional information related to financing activity.
Significant Factors
- -------------------
Federal EPA Complaint and Notice of Violation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", OPCo and certain affiliated companies have been
involved in litigation since 1999 regarding generating plant emissions under the
Clean Air Act. Federal EPA and a number of states alleged OPCo, certain
affiliated companies and eleven unaffiliated utilities made modifications to
generating units at coal-fired generating plants in violation of the Clean Air
Act. Federal EPA filed complaints against AEP subsidiaries in U.S. District
Court for the Southern District of Ohio. A separate lawsuit initiated by certain
special interest groups was consolidated with the Federal EPA case. The alleged
modification of the generating units occurred 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 Clear Air Act proceedings and
is 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. In the event 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. See Note
7 for further discussion.
NOx Reductions
Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
under the Clean Air Act requiring substantial reductions in NOx emissions in a
number of eastern states, including certain states in which the AEP System's
generating plants are located. The compliance date for the rules is May 31,
2004.
We are installing selective catalytic reduction (SCR) technology and non-SCR
technology to reduce NOx emissions on certain units to comply with these rules.
Our estimates indicate that compliance with the rules could result in required
capital expenditures in a range of $524 million to $853 million. The actual cost
to comply could be significantly different than the estimates depending upon the
compliance alternatives selected to achieve reductions in NOx emissions. Unless
any capital or operating costs for additional pollution control equipment are
recovered from customers, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition. See Note 7 for further
discussion.
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the 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.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Domestic Power
--------------
(in thousands)
Beginning Balance December 31, 2002 $94,106
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (39,181)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 369
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (4,159)
Changes in Fair Value of Risk Management
Contracts (d) 12,431
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) -
-------
Total MTM Risk Management Contract Net
Assets 63,566
Net Non-Trading Related Derivative
Contracts (2,745)
-------
Net Fair Value of Risk Management and Derivative
Contracts June 30, 2003 $60,821
=======
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior to
2003.
(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 2003. 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 2003.
(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.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $17,123 $15,750 $4,418 $3,919 $1,252 $ - $42,462
Prices Based on Models and Other
Valuation Methods (b) 632 1,734 1,929 3,348 3,385 10,076 21,104
------- ------- ------ ------ ------ ------- -------
Total $17,755 $17,484 $6,347 $7,267 $4,637 $10,076 $63,566
======= ======= ====== ====== ====== ======= =======
(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.
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. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2003
Domestic Foreign
Power Currency Consolidated
-------- -------- ------------
(in thousands)
Accumulated OCI, December 31, 2002 $ (354) $(384) $ (738)
----------------------------------
Changes in Fair Value (a) (1,690) - (1,690)
Reclassifications from OCI to Net
Income (b) 107 7 114
------- ----- -------
Accumulated OCI Derivative Gain (Loss)
June 30, 2003 $(1,937) $(377) $(2,314)
======= ===== =======
(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 OCI 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 Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $1,331 thousand loss.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
June 30, 2003 December 31, 2002
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$270 $1,836 $1,022 $270 $1,150 $3,521 $1,259 $255
OHIO POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electric Generation, Transmission and Distribution $387,892 $395,972 $ 838,779 $ 806,990
Sales to AEP Affiliates 151,494 125,393 291,238 235,027
-------- -------- ---------- ----------
TOTAL OPERATING REVENUES 539,386 521,365 1,130,017 1,042,017
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel for Electric Generation 153,446 149,097 307,094 291,433
Purchased Electricity for Resale 17,454 15,572 36,845 33,201
Purchased Electricity from AEP Affiliates 24,428 20,265 47,212 34,492
Other Operation 84,641 105,975 177,622 196,089
Maintenance 53,411 29,957 88,868 58,945
Depreciation and Amortization 60,223 61,176 121,775 123,797
Taxes Other Than Income Taxes 39,613 43,292 86,768 89,131
Income Taxes 26,339 34,985 85,132 70,167
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES 459,555 460,319 951,316 897,255
-------- -------- ---------- ----------
OPERATING INCOME 79,831 61,046 178,701 144,762
NONOPERATING INCOME 4,594 18,975 783 31,900
NONOPERATING EXPENSES 7,102 3,853 17,725 11,260
NONOPERATING INCOME TAX EXPENSE
(CREDIT) 1,564 626 (3,092) 4,348
INTEREST CHARGES 19,482 20,194 40,224 41,655
-------- -------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 56,277 55,348 124,627 119,399
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) - - 124,632 -
-------- -------- ---------- ----------
NET INCOME 56,277 55,348 249,259 119,399
PREFERRED STOCK DIVIDEND REQUIREMENTS 315 315 629 629
---------- ---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 55,962 $ 55,033 $ 248,630 $ 118,770
========== ========== ========== ==========
The common stock of OPCo is wholly owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------- -----
(in thousands)
JANUARY 1, 2002 $321,201 $462,483 $401,297 $ (196) $1,184,785
Common Stock Dividends (65,164) (65,164)
Preferred Stock Dividends (629) (629)
----------
1,118,992
----------
Comprehensive Income:
Other Comprehensive Income (Loss)
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 1,769 1,769
Net Income 119,399 119,399
----------
Total Comprehensive Income 121,168
-------- -------- -------- -------- ----------
JUNE 30, 2002 $321,201 $462,483 $454,903 $ 1,573 $1,240,160
======== ======== ======== ======== ==========
JANUARY 1, 2003 $321,201 $462,483 $522,316 $(72,886) $1,233,114
Common Stock Dividends (83,867) (83,867)
Preferred Stock Dividends (629) (629)
----------
1,148,618
----------
Comprehensive Income:
Other Comprehensive Income (Loss)
Net of Taxes:
Unrealized Loss on Cash Flow Hedges (1,576) (1,576)
Minimum Pension Liability 5,624 5,624
Net Income 249,259 249,259
----------
Total Comprehensive Income 253,307
-------- -------- -------- -------- ----------
JUNE 30, 2003 $321,201 $462,483 $687,079 $(68,838) $1,401,925
======== ======== ======== ======== ==========
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $3,217,096 $3,116,825
Transmission 902,897 905,829
Distribution 1,133,401 1,114,600
General 228,894 260,153
Construction Work in Progress 259,299 288,419
---------- ----------
Total Electric Utility Plant 5,741,587 5,685,826
Accumulated Depreciation and Amortization 2,354,453 2,566,828
---------- ----------
NET ELECTRIC UTILITY PLANT 3,387,134 3,118,998
---------- ----------
OTHER PROPERTY AND INVESTMENTS 55,453 61,686
---------- ----------
LONG-TERM RISK MANAGEMENT ASSETS 80,541 103,230
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 8,675 5,285
Accounts Receivable:
Customers 77,238 95,100
Affiliated Companies 136,697 124,244
Miscellaneous 26,438 19,281
Allowance for Uncollectible Accounts (921) (909)
Fuel 86,886 87,409
Materials and Supplies 88,421 85,379
Risk Management Assets 75,398 92,108
Prepayments and Other 32,625 12,083
---------- ----------
TOTAL CURRENT ASSETS 531,457 519,980
---------- ----------
REGULATORY ASSETS 530,805 568,641
---------- ----------
DEFERRED CHARGES AND OTHER ASSETS 105,651 84,497
---------- ----------
TOTAL ASSETS $4,691,041 $4,457,032
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 462,483 462,483
Accumulated Other Comprehensive Income (Loss) (68,838) (72,886)
Retained Earnings 687,079 522,316
---------- ----------
Total Common Shareholder's Equity 1,401,925 1,233,114
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,646 16,648
Subject to Mandatory Redemption 8,350 8,850
Long-term Debt 1,175,839 677,649
Long-term Debt - Affiliated Companies - 240,000
---------- ----------
TOTAL CAPITALIZATION 2,602,760 2,176,261
---------- ----------
OTHER NONCURRENT LIABILITIES 222,900 227,689
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General 59,815 89,665
Long-term Debt Due Within One Year - Affiliated Companies - 60,000
Short-term Debt - Affiliates - 275,000
Advances from Affiliates 362,860 129,979
Accounts Payable - General 97,986 170,563
Accounts Payable - Affiliated Companies 64,821 145,718
Customer Deposits 22,493 12,969
Taxes Accrued 128,075 111,778
Interest Accrued 28,914 18,809
Obligations Under Capital Leases 9,482 14,360
Risk Management Liabilities 50,905 61,839
Other 55,910 80,608
---------- ----------
TOTAL CURRENT LIABILITIES 881,261 1,171,288
---------- ----------
DEFERRED INCOME TAXES 880,981 794,387
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 17,223 18,748
---------- ----------
LONG-TERM RISK MANAGEMENT LIABILITIES 44,213 39,702
---------- ----------
DEFERRED CREDITS 41,703 28,957
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $4,691,041 $4,457,032
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $249,259 $119,399
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes (124,632) -
Depreciation and Amortization 121,775 123,797
Deferred Income Taxes 372 (18,653)
Mark to Market of Risk Management Contracts 26,381 (24,493)
Changes in Certain Assets and Liabilities:
Accounts Receivable, net (1,736) (66,769)
Fuel, Materials and Supplies (2,519) 4,471
Accrued Utility Revenues 5,995 (5,276)
Prepayments and Other (20,542) (15,759)
Accounts Payable (153,474) 95,017
Customer Deposits 9,524 3,585
Taxes Accrued 16,297 14,274
Interest Accrued 10,105 4,286
Deferred Property Taxes 29,337 30,046
Change in Other Assets (47,741) 6,667
Change in Other Liabilities (43,559) (30,834)
--------- ---------
Net Cash Flows From Operating Activities 74,842 239,758
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (117,761) (158,080)
Proceeds from Sale of Property and Other 3,276 283
--------- ---------
Net Cash Flows Used For Investing Activities (114,485) (157,797)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 500,000 -
Change in Advances to/from Affiliates, net 232,881 (163,144)
Change in Short-term Debt - Affiliates (275,000) 150,000
Retirement of Long-term Debt (29,850) (5,000)
Retirement of Long-term Debt - Affiliated (300,000) -
Retirement of Cumulative Preferred Stock (502) -
Dividends Paid on Common Stock (83,867) (65,164)
Dividends Paid on Cumulative Preferred Stock (629) (629)
--------- ---------
Net Cash Flows From (Used For) Financing Activities 43,033 (83,937)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 3,390 (1,976)
Cash and Cash Equivalents at Beginning of Period 5,285 8,848
--------- ---------
Cash and Cash Equivalents at End of Period $ 8,675 $ 6,872
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $29,304,000 and
$36,585,000 and for income taxes was $26,455,000 and $29,187,000 in 2003 and
2002, respectively. Noncash acquisitions under capital leases were $98,000 in
2002.
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
Net Income increased year-to-date and for the second quarter by $9 million and
$6 million, respectively. Large swings occurred in revenues, fuel and purchased
power due to fuel price market volatility (primarily natural gas), however,
income is generally not significantly affected due to the functioning of the
fuel adjustment clause in Oklahoma.
Operating Income
Operating Income increased $13 million year-to-date and $9 million for the
second quarter primarily due to the following:
o Increased wholesale margins year-to-date of $2 million and for the second
quarter of $1 million.
o Increased other customer service revenues of $3 million year-to-date and $1
million for the second quarter due to increased rents and service work for
customers.
o Decreased Other Operation and Maintenance expenses of $2 million
year-to-date and $2 million for the second quarter due in large part to the
absence in 2003 of storm damage that occurred in the first quarter 2002 and
reduced transmission and power plant maintenance during the second quarter
2003.
o Decreased Income Taxes of $1 million year-to-date and $3 million for the
second quarter due to state income tax accrual adjustments offset by
increases in pre-tax operating book income.
The increase in Operating Income was partially offset by:
o Increased Taxes Other Than Income Taxes of $2 million year-to-date due
primarily to increased property value assessments and franchise taxes.
Other Impacts on Earnings
Nonoperating Income decreased approximately $1 million primarily due to a gain
on the disposition of an investment in 2002. No such transaction occurred in the
current year.
Interest Charges increased $5 million year-to-date and $1 million for the second
quarter as a result of replacing floating rate short-term debt with longer term
fixed rate 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-
In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of our rating for unsecured debt from A2 to Baa1. The completion of this review
was a culmination of ratings action started during 2002. In March 2003, S&P
lowered AEP and its subsidiaries' senior unsecured ratings from BBB+ to BBB
along with the first mortgage bonds of AEP subsidiaries.
Financing Activity
Retired $35 million of first mortgage bonds on April 1, 2003 with coupon of
6.25% due 2003, and received a $50 million capital contribution from our parent
company. See Note 12 for additional information related to financing activity.
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the 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.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Domestic Power
--------------
(in thousands)
Beginning Balance December 31, 2002 $ 3,545
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) 220
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) -
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission -
Changes in Fair Value of Risk Management
Contracts (d) -
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) 12,120
-------
Total MTM Risk Management Contract Net
Assets 15,885
Net Non-Trading Related Derivative
Contracts (1,417)
-------
Net Fair Value of Risk Management and Derivative
Contracts June 30, 2003 $14,468
=======
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior to
2003.
(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 2003. 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 2003.
(d)"Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather, etc.
(e)"Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Operations. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $3,430 $3,724 $1,251 $1,109 $ 354 $ - $ 9,868
Prices Based on Models and Other
Valuation Methods (b) 222 491 546 948 958 2,852 6,017
------ ------ ------ ------ ------ ------ -------
Total $3,652 $4,215 $1,797 $2,057 $1,312 $2,852 $15,885
====== ====== ====== ====== ====== ====== =======
(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.
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. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2003
Domestic
Power
-----
(in thousands)
Accumulated OCI, December 31, 2002 $ (42)
----------------------------------
Changes in Fair Value (a) (903)
Reclassifications from OCI to Net
Income (b) 24
-----
Accumulated OCI Derivative Gain (Loss) June
30, 2003 $(921)
=====
(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 OCI 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 Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $626 thousand loss.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
June 30, 2003 December 31, 2002
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$128 $873 $486 $128 $136 $415 $148 $30
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electric Generation, Transmission and Distribution $267,213 $152,168 $ 505,480 $ 299,060
Sales to AEP Affiliates 10,023 6,162 14,418 8,256
-------- -------- --------- ---------
TOTAL OPERATING REVENUES 277,236 158,330 519,898 307,316
-------- -------- --------- ---------
OPERATING EXPENSES:
Fuel for Electric Generation 135,395 33,772 238,569 91,869
Purchased Electricity for Resale 6,863 10,364 19,354 8,020
Purchased Electricity from AEP Affiliates 28,276 12,073 70,383 28,918
Other Operation 31,684 34,249 63,302 60,888
Maintenance 12,366 11,886 21,760 26,055
Depreciation and Amortization 21,359 21,061 42,853 41,977
Taxes Other Than Income Taxes 8,439 8,083 18,085 15,931
Income Taxes 4,139 6,641 3,731 5,047
-------- -------- --------- ---------
TOTAL OPERATING EXPENSES 248,521 138,129 478,037 278,705
-------- -------- --------- ---------
OPERATING INCOME 28,715 20,201 41,861 28,611
NONOPERATING INCOME 72 1,223 722 1,329
NONOPERATING EXPENSE (CREDIT) (276) 69 163 664
NONOPERATING INCOME TAX EXPENSE (CREDIT) (155) (100) (355) (241)
INTEREST CHARGES 11,291 9,835 24,157 19,545
-------- -------- --------- ---------
NET INCOME 17,927 11,620 18,618 9,972
PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53 106 106
-------- -------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $ 17,874 $ 11,567 $ 18,512 $ 9,866
======== ======== ========= =========
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 AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------- -----
(in thousands)
JANUARY 1, 2002 $157,230 $180,016 $142,994 $ - $480,240
Common Stock Dividends (44,911) (44,911)
Preferred Stock Dividends (106) (106)
--------
435,223
--------
Comprehensive Income:
Other Comprehensive Income 200 200
Net Income 9,972 9,972
--------
Total Comprehensive Income 10,172
-------- -------- -------- ------- --------
JUNE 30, 2002 $157,230 $180,016 $107,949 $ 200 $445,395
======== ======== ======== ======== ========
JANUARY 1, 2003 $157,230 $180,016 $116,474 $(54,473) $399,247
Capital Contribution from Parent 50,000 50,000
Common Stock Dividends (7,500) (7,500)
Preferred Stock Dividends (106) (106)
Distribution of Investment in AEMT, Inc.
Preferred Shares to Parent (548) (548)
--------
441,093
--------
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Minimum Pension Liability (58) (58)
Unrealized Loss on Cash Flow
Power Hedges (879) (879)
Net Income 18,618 18,618
--------
Total Comprehensive Income 17,681
-------- -------- -------- -------- --------
JUNE 30, 2003 $157,230 $230,016 $126,938 $(55,410) $458,774
======== ======== ======== ======== ========
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,061,688 $1,040,520
Transmission 434,390 432,846
Distribution 1,006,691 990,947
General 190,203 206,747
Construction Work in Progress 67,107 88,444
---------- ----------
Total Electric Utility Plant 2,760,079 2,759,504
Accumulated Depreciation and Amortization 1,244,909 1,239,855
---------- ----------
NET ELECTRIC UTILITY PLANT 1,515,170 1,519,649
---------- ----------
OTHER PROPERTY AND INVESTMENTS 4,827 5,383
---------- ----------
LONG-TERM RISK MANAGEMENT ASSETS 15,154 4,481
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 18,573 16,774
Accounts Receivable:
Customers 37,761 31,687
Affiliated Companies 13,577 14,139
Allowance for Uncollectible Accounts (41) (84)
Fuel Inventory 19,101 19,973
Materials and Supplies 37,379 37,375
Under-recovered Fuel Costs 64,820 76,470
Risk Management Assets 16,360 3,841
Prepayments and Other 3,103 2,735
---------- ----------
TOTAL CURRENT ASSETS 210,633 202,910
---------- ----------
REGULATORY ASSETS 26,221 26,150
---------- ----------
DEFERRED CHARGES 40,554 18,117
---------- ----------
TOTAL ASSETS $1,812,559 $1,776,690
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
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 230,016 180,016
Accumulated Other Comprehensive Income (Loss) (55,410) (54,473)
Retained Earnings 126,938 116,474
---------- ----------
Total Common Shareholder's Equity 458,774 399,247
Cumulative Preferred Stock Not Subject
to Mandatory Redemption 5,267 5,267
PSO-Obligated, Mandatorily Redeemable Preferred Securities of
Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000
Long-term Debt 445,576 445,437
---------- ----------
TOTAL CAPITALIZATION 984,617 924,951
---------- ----------
OTHER NONCURRENT LIABILITIES 55,324 54,761
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 65,000 100,000
Advances from Affiliates 68,555 86,105
Accounts Payable - General 74,609 61,169
Accounts Payable - Affiliated Companies 65,898 78,076
Customer Deposits 24,678 21,789
Taxes Accrued 12,634 6,854
Interest Accrued 5,403 6,979
Risk Management Liabilities 11,065 3,260
Other 17,901 24,957
---------- ----------
TOTAL CURRENT LIABILITIES 345,743 389,189
---------- ----------
DEFERRED INCOME TAXES 353,509 341,396
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 31,306 32,201
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 36,079 32,611
---------- ----------
LONG-TERM RISK MANAGEMENT LIABILITIES 5,981 1,581
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $1,812,559 $1,776,690
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 18,618 $ 9,972
Adjustments to Reconcile Net Income to Net Cash Flows
From (Used For) Operating Activities:
Depreciation and Amortization 42,853 41,977
Deferred Income Taxes 10,940 21,559
Deferred Investment Tax Credits (895) (895)
Changes in Certain Assets and Liabilities:
Accounts Receivable, net (5,555) (23,952)
Fuel, Materials and Supplies 868 (3,226)
Accounts Payable 1,262 25,818
Taxes Accrued 5,780 (2,188)
Fuel Recovery 11,650 (53,156)
Deferred Property Taxes (16,478) (16,184)
Changes in Other Assets (9,551) (2,968)
Changes in Other Liabilities (13,004) (4,387)
-------- --------
Net Cash Flows From (Used For) Operating Activities 46,488 (7,630)
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures (34,660) (35,095)
Other 127 (963)
-------- --------
Net Cash Flows Used For Investing Activities (34,533) (36,058)
-------- --------
FINANCING ACTIVITIES:
Capital Contributions from Parent 50,000 -
Change in Advances to/from Affiliates, net (17,550) 89,863
Retirement of Long-term Debt (35,000) -
Dividends Paid on Common Stock (7,500) (44,911)
Dividends Paid on Cumulative Preferred Stock (106) (106)
-------- --------
Net Cash Flows From (Used For) Financing Activities (10,156) 44,846
-------- --------
Net Increase in Cash and Cash Equivalents 1,799 1,158
Cash and Cash Equivalents at Beginning of Period 16,774 5,795
-------- --------
Cash and Cash Equivalents at End of Period $ 18,573 $ 6,953
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $24,107,000 and
$17,870,000 and for income taxes was $8,975,000 and $2,575,000 in 2003 and 2002,
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.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
Net Income increased $13 million year-to-date due in large part to the adoption
of SFAS 143, which resulted in a Cumulative Effect of Accounting Change of $9
million in the first quarter. Net Income for the second quarter increased $2
million due to increased wholesale margins and gains in risk management
activities. Although large swings occurred in revenues, fuel and purchased
power, due to fuel price market volatility (primarily natural gas), income was
generally not affected due to the functioning of fuel adjustment clauses.
Operating Income
Operating Income increased by $8 million year-to-date and $4 million for the
quarter primarily due to the following:
o Increased wholesale margins both year-to-date and for the quarter.
o Increased gains in risk management activities of $9 million year-to-date
and $5 million for the quarter.
o Other Operation expense decreased $9 million year-to-date and
$7 million for the quarter primarily due to SWEPCo's ability to defer a
portion of fuel expense in the state of Louisiana.
o Maintenance decreased $1 million year-to-date and $2 million for the
quarter due to reduced scheduled power plant maintenance.
The increase in Operating Income was partially offset by:
o Taxes Other Than Income Taxes increased year-to-date by $2 million due to
increased property taxes resulting from adjustments for revised tax
valuations.
o Income Taxes increased for both year-to-date and for the quarter due to an
increase in pre-tax operating book income. The quarter results are offset
slightly by state income tax accrual adjustments.
Other Impacts on Earnings
Interest Charges increased $3 million year-to-date and $1 million for the
quarter primarily due to higher overall levels of outstanding debt and higher
average interest rates as floating rate debt was replaced with unsecured fixed
rate debt.
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 (see
Notes 2 and 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 Baa1 BBB A-
In February 2003, Moody's Investors Service (Moody's) completed their review
of AEP and its rated subsidiaries. The results of that review included a
downgrade of our rating for unsecured debt from A2 to Baa1. The completion of
this review was a culmination of ratings action started during 2002. In March
2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+
to BBB along with the first mortgage bonds of AEP subsidiaries.
Cash Flow
Cash flows for six months ended June 30, 2003 and 2002 were as follows:
2003 2002
-------------- --------------
(in thousands)
Cash and cash equivalents at beginning of period $ 2,069 $ 5,415
Cash flows from (used for):
Operating activities 113,291 88,594
Investing activities (62,469) (35,979)
Financing activities (42,391) (42,170)
--------- ---------
Net increase in cash and cash equivalents 8,431 10,445
--------- ---------
Cash and cash equivalents at end of period $ 10,500 $ 15,860
========= =========
Operating Activities
Cash flows from operating activities increased $25 million in the first six
months of 2003 compared to the first six months of 2002 primarily due to a
build-up of fuel inventory during 2002.
Investing Activities
Cash spent on investing activities increased $26 million in comparison to the
prior year. Investment expenditures of $46 million in the current year were
related to projects for improved transmission and distribution service
reliability.
Financing Activities
Cash flows used for financing activities in the first half of 2003 were
comparable to the first half of 2002. During the first quarter of 2003 we
retired $55 million of first mortgage bonds at maturity. In April 2003, we
issued $100 million of senior unsecured debt due 2015 at a coupon of 5.375%. In
May 2003, our mining subsidiary issued $44 million of notes due in 2011 at a
coupon of 4.47%. See Note 12 for additional information related to financing
activity.
Significant Factors
- -------------------
NOx Reductions
The Texas Commission on Environmental Quality adopted rules requiring
significant reductions in NOx emissions from utility sources, including SWEPCo.
Our compliance date is May 2005. We are installing non-selective catalytic
reduction technology to reduce NOx emissions on certain units to comply with
these rules. Our estimates indicate that compliance with the rules could result
in required capital expenditures of approximately $35 million. The actual cost
to comply could be significantly different than the estimate depending upon the
compliance alternatives selected to achieve reductions in NOx emissions. Unless
any capital or operating costs for additional pollution control equipment are
recovered from customers, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition. See Note 7 for further
discussion.
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) 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
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the 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.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Domestic Power
- -------------- (in thousands)
Beginning Balance December 31, 2002 $ 4,050
- -----------------------------------
(Gain) Loss from Contracts Realized/Settled During the
Period (a) (218)
Fair Value of New Contracts When Entered Into During the
Period (b) -
Net Option Premiums Paid/(Received) (c) -
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission 151
Changes in Fair Value of Risk Management
Contracts (d) 5,012
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) 9,151
-------
Total MTM Risk Management Contract Net
Assets 18,146
Net Non-Trading Related Derivative
Contracts (1,618)
-------
Net Fair Value of Risk Management and Derivative
Contracts June 30, 2003 $16,528
=======
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior
to 2003.
(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 2003. 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 2003.
(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.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:
o The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $3,917 $4,254 $1,429 $1,267 $ 405 $ - $11,272
Prices Based on Models and Other
Valuation Methods (b) 254 561 624 1,083 1,094 3,258 6,874
------ ------ ------ ------ ------ ------ -------
Total $4,171 $4,815 $2,053 $2,350 $1,499 $3,258 $18,146
====== ====== ====== ====== ====== ====== =======
(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.
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. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2003
Domestic
Power
-----
(in thousands)
Accumulated OCI, December 31, 2002 $ (48)
----------------------------------
Changes in Fair Value (a) (1,031)
Reclassifications from OCI to Net
Income (b) 27
-------
Accumulated OCI Derivative Gain (Loss)
June 30, 2003 $(1,052)
=======
(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 OCI 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 Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $715 thousand loss.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
June 30, 2003 December 31, 2002
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$146 $997 $555 $146 $155 $474 $170 $34
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electric Generation, Transmission and
Distribution $264,598 $248,849 $ 487,521 $ 448,149
Sales to AEP Affiliates 16,708 14,225 49,063 37,184
-------- -------- --------- ---------
TOTAL OPERATING REVENUES 281,306 263,074 536,584 485,333
-------- -------- --------- ---------
OPERATING EXPENSES:
Fuel for Electric Generation 110,706 95,207 213,716 184,090
Purchased Electricity for Resale 10,365 3,444 22,932 7,514
Purchased Electricity from AEP Affiliates 14,841 15,031 25,651 20,516
Other Operation 36,656 44,131 77,513 86,282
Maintenance 18,931 20,942 31,748 32,780
Depreciation and Amortization 30,868 30,533 58,903 60,673
Taxes Other Than Income Taxes 13,168 12,889 29,041 27,355
Income Taxes 10,183 9,317 15,448 12,074
-------- -------- --------- ---------
TOTAL OPERATING EXPENSES 245,718 231,494 474,952 431,284
-------- -------- --------- ---------
OPERATING INCOME 35,588 31,580 61,632 54,049
NONOPERATING INCOME 475 313 1,347 415
NONOPERATING EXPENSE (CREDIT) 355 (20) 876 546
NONOPERATING INCOME TAX EXPENSE (CREDIT) (105) (137) (55) (109)
INTEREST CHARGES 15,223 13,895 31,077 27,713
--------- --------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 20,590 18,155 31,081 26,314
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) - - 8,517 -
-------- -------- --------- ---------
NET INCOME 20,590 18,155 39,598 26,314
PREFERRED STOCK DIVIDEND REQUIREMENTS 58 58 115 115
-------- -------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $ 20,532 $ 18,097 $ 39,483 $ 26,199
======== ======== ========= =========
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 AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------- -----
(in thousands)
JANUARY 1, 2002 $135,660 $245,003 $308,915 $ - $689,578
Common Stock Dividends (37,927) (37,927)
Preferred Stock Dividends (115) (115)
--------
651,536
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Power Hedges 230 230
Net Income 26,314 26,314
--------
Total Comprehensive Income 26,544
-------- -------- -------- -------- --------
JUNE 30, 2002 $135,660 $245,003 $297,187 $ 230 $678,080
======== ======== ======== ======== ========
JANUARY 1, 2003 $135,660 $245,003 $334,789 $(53,683) $661,769
Common Stock Dividends (36,396) (36,396)
Preferred Stock Dividends (115) (115)
--------
625,258
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (1,004) (1,004)
Net Income 39,598 39,598
--------
Total Comprehensive Income 38,594
-------- -------- -------- -------- --------
JUNE 30, 2003 $135,660 $245,003 $337,876 $(54,687) $663,852
======== ======== ======== ======== ========
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,505,349 $1,503,722
Transmission 580,264 575,003
Distribution 1,062,736 1,063,564
General 406,903 378,130
Construction Work in Progress 86,510 75,755
---------- ----------
Total Electric Utility Plant 3,641,762 3,596,174
Accumulated Depreciation and Amortization 1,736,945 1,697,338
---------- ----------
NET ELECTRIC UTILITY PLANT 1,904,817 1,898,836
---------- ----------
OTHER PROPERTY AND INVESTMENTS 6,521 5,978
---------- ----------
LONG-TERM RISK MANAGEMENT ASSETS 17,311 5,119
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 10,500 2,069
Advances to Affiliates 70,945 -
Accounts Receivable:
Customers 57,192 62,359
Affiliated Companies 14,681 19,253
Allowance for Uncollectible Accounts (2,085) (2,128)
Fuel Inventory 54,665 61,741
Materials and Supplies 33,170 33,539
Under-recovered Fuel Costs - 2,865
Risk Management Assets 18,688 4,388
Prepayments and Other 18,072 17,851
---------- ----------
TOTAL CURRENT ASSETS 275,828 201,937
---------- ----------
REGULATORY ASSETS 52,983 49,233
---------- ----------
DEFERRED CHARGES 62,526 47,572
---------- ----------
TOTAL ASSETS $2,319,986 $2,208,675
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
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
Accumulated Other Comprehensive Income (Loss) (54,687) (53,683)
Retained Earnings 337,876 334,789
---------- ----------
Total Common Shareholder's Equity 663,852 661,769
Preferred Stock 4,700 4,701
SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust
Holding Solely Junior Subordinated Debentures of SWEPCo 110,000 110,000
Long-term Debt 734,418 637,853
---------- ----------
TOTAL CAPITALIZATION 1,512,970 1,414,323
---------- ----------
OTHER NONCURRENT LIABILITIES 83,057 78,494
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 47,424 55,595
Advances from Affiliates, net - 23,239
Accounts Payable - General 55,220 62,139
Accounts Payable - Affiliated Companies 53,343 58,773
Customer Deposits 23,862 20,110
Taxes Accrued 42,873 19,081
Interest Accrued 16,306 17,051
Risk Management Liabilities 12,639 3,724
Over-recovered Fuel 213 17,226
Other 32,610 34,565
---------- ----------
TOTAL CURRENT LIABILITIES 284,490 311,503
---------- ----------
DEFERRED INCOME TAXES 348,445 341,064
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 42,027 44,190
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 42,165 17,295
---------- ----------
LONG-TERM RISK MANAGEMENT LIABILITIES 6,832 1,806
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $2,319,986 $2,208,675
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 39,598 $ 26,314
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Depreciation and Amortization 58,903 60,673
Deferred Income Taxes 2,413 (9,004)
Deferred Investment Tax Credits (2,163) (2,262)
Cumulative Effect of Accounting Changes (8,517) -
Mark-to-Market of Risk Management Contracts (13,945) 7,834
Changes in Certain Assets and Liabilities:
Accounts Receivable, net 9,696 (55,025)
Fuel, Materials and Supplies 7,445 (30,528)
Accounts Payable (12,349) 74,657
Taxes Accrued 23,792 24,640
Fuel Recovery (14,148) 11,647
Deferred Property Taxes (18,630) (17,545)
Change in Other Assets 9,701 10,995
Change in Other Liabilities 31,495 (13,802)
-------- --------
Net Cash Flows From Operating Activities 113,291 88,594
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures (62,883) (35,695)
Proceeds from Sale of Assets and Other 414 (284)
-------- --------
Net Cash Flows Used For Investing Activities (62,469) (35,979)
-------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 144,324 198,616
Retirement of Long-term Debt (56,020) (150,450)
Change in Advances to/from Affiliates, net (94,184) (52,294)
Dividends Paid on Common Stock (36,396) (37,927)
Dividends Paid on Cumulative Preferred Stock (115) (115)
-------- --------
Net Cash Flows Used For Financing Activities (42,391) (42,170)
-------- --------
Net Increase in Cash and Cash Equivalents 8,431 10,445
Cash and Cash Equivalents at Beginning of Period 2,069 5,415
-------- --------
Cash and Cash Equivalents at End of Period $ 10,500 $ 15,860
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $27,741,000 and
$21,331,000 and for income taxes was $17,062,000 and $24,479,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
NOTES TO RESPECTIVE FINANCIAL STATEMENTS
JUNE 30, 2003
(UNAUDITED)
The notes to 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. General AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
2. New Accounting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
Pronouncements
3. Cumulative Effect of AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
Accounting Changes
4. Goodwill and Other SWEPCo
Intangible Assets
5. Rate Matters APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
6. Customer Choice and APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC
Industry Restructuring
7. Commitments and AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
Contingencies
8. Guarantees AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
9. Sustained Earnings AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
Improvement
Initiative
10. Business Segments AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
11. Leases OPCo
12. Financing and Related APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
Activities
1. GENERAL
-------
The accompanying unaudited interim financial statements should be read
in conjunction with the 2002 Annual Report (as updated by the Current
Report on Form 8-K dated May 14, 2003) as incorporated in and filed with
the Form 10-K.
Certain prior period financial statement items have been reclassified to
conform to current period presentation. These items include the effects
of discontinued operations, gains and losses associated with derivative
trading contracts presented on a net basis in accordance with EITF 02-3,
and counterparty netting in accordance with FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts" and EITF Topic
D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy
under FASB Interpretation No. 39". Such reclassifications had no effect
on previously reported Net Income.
In the opinion of management, the unaudited interim financial statements
reflect all normal recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for
interim periods.
2. NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------
SFAS 143 "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. SFAS 143 requires that a cumulative
effect of change in accounting principle be recognized for the
cumulative accretion and accumulated depreciation that would have been
recognized had SFAS 143 been applied to existing legal obligations for
asset retirements. In addition, the cumulative effect of change in
accounting principle is favorably affected by the reversal of
accumulated removal cost that had previously been recorded for
generation that does not qualify as a legal obligation which was
collected in depreciation rates by certain formerly regulated
subsidiaries.
We completed a review of our asset retirement obligations and concluded
that at present, we have related legal liabilities for nuclear
decommissioning costs for I&M's Cook Plant and TCC's partial ownership
in the South Texas Project, as well as liabilities for the retirement of
certain ash ponds. Since we presently recover our nuclear
decommissioning costs in our regulated cash flow and thus had existing
balances recorded for such nuclear retirement obligations, we recognized
the cumulative difference in the amount already provided through rates
versus the new methodology of SFAS 143, as a regulatory asset or
liability. Similarly, a regulatory asset was recorded for the cumulative
effect of certain retirement costs for ash ponds related to our
regulated operations. In the first quarter of 2003, AEP recorded an
unfavorable cumulative effect for our non-regulated operations. See the
table later in this section for a summary by registrant subsidiary of
the cumulative effect of changes in accounting principles for the six
months ended June 30, 2003.
Certain of AEP's registrant subsidiaries have recorded in Accumulated
Depreciation and Amortization, removal costs collected from ratepayers
for certain assets that do not have associated legal asset retirement
obligations. To the extent that such registrant subsidiaries have now
been deregulated, in the first quarter 2003 the registrant subsidiaries
reversed the balance of such removal costs from accumulated depreciation
which resulted in a net favorable cumulative effect in the first quarter
of 2003. However, the registrant subsidiaries did not adjust the balance
of such removal costs for their regulated operations, and in accordance
with the present method of recovery, will continue to record such
amounts through depreciation expense and accumulated depreciation.
The following is a summary by registrant subsidiary of the regulatory
liabilities for removal costs included in Accumulated Depreciation and
Amortization:
June 30, 2003 December 31, 2002
------------- -----------------
(in millions)
AEGCo $ 28.7 $ 28.0
APCo 88.7 94.6
CSPCo 98.5 96.0
I&M 257.7 250.5
KPCo 21.5 23.7
OPCo 97.6 97.0
PSO 206.2 202.6
SWEPCo 223.8 219.5
TCC 95.8 97.5
TNC 75.4 75.0
The following is a summary by registrant subsidiary of the cumulative
effect of changes in accounting principles, as a result of SFAS 143, for
the six months ended June 30, 2003:
Pre-tax Income (Loss) After-tax Income (Loss)
-------------------- ----------------------
Reversal of Reversal of
Cost of Cost of
Ash Ponds Removal Ash Ponds Removal
--------- -------- --------- -----------
AEGCo $ - $ - $ - $ -
APCo (18.2) 146.5 (11.4) 91.7
CSPCo (7.8) 56.8 (4.7) 33.9
I&M - - - -
KPCo - - - -
OPCo (36.8) 250.4 (21.9) 149.3
PSO - - - -
SWEPCo - 13.0 - 8.4
TCC - - - -
TNC - 4.7 - 3.1
We have identified, but not recognized, asset retirement obligation
liabilities related to electric transmission and distribution as a
result of certain easements on property on which we have assets.
Generally, such easements are perpetual and require only the retirement
and removal of our assets upon the cessation of the property's use. The
retirement obligation is not estimable for such easements since we plan
to use our facilities indefinitely. The retirement obligation would only
be recognized if and when we abandon or cease the use of specific
easements.
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, 2003 Accretion June 30, 2003
--------------- ---------- -------------
AEGCo (a) $ 1.1 $ - $ 1.1
APCo (a) 20.1 0.8 20.9
CSPCo (a) 8.1 0.2 8.3
I&M (b) 516.1 18.2 534.3
OPCo (a) 39.5 1.6 41.1
TCC (c) 203.2 7.6 210.8
(a) Consists of asset retirement obligations related
to ash ponds.
(b) Consists of asset retirement obligations related
to ash ponds ($1.1 million at June 30, 2003) and
nuclear decommissioning costs for the Cook Plant
($533.2 million at June 30, 2003).
(c) Consists of asset retirement obligations related
to nuclear decommissioning costs for STP.
Accretion expense is included in Other Operation expense in the
respective Income Statements of the individual subsidiary registrants.
As of June 30, 2003 and December 31, 2002, the fair value of assets that
are legally restricted for purposes of settling the nuclear
decommissioning liabilities totaled $778 million ($669 million for I&M
and $109 million for TCC) and $716 million ($618 million for I&M and $98
million for TCC), respectively, recorded in Nuclear Decommissioning and
Spent Nuclear Fuel Disposal Trust Funds on I&M's Consolidated Balance
Sheets and in Nuclear Decommissioning Trust Fund on TCC's Consolidated
Balance Sheets.
Pro forma net income has not been presented for the period ended June
30, 2003 or the years ended December 31, 2002, 2001 and 2000 because the
pro forma application of SFAS 143 would result in pro forma net income
not materially different from the actual amounts reported for those
periods.
The following is a summary by registrant subsidiary of the pro forma
liability for asset retirement obligations which has been calculated as
if SFAS 143 had been adopted as of the beginning of each period
presented:
December 31, 2002 December 31, 2001
----------------- -----------------
(in millions)
AEGCo $ 1.1 $ 1.0
APCo 20.1 18.7
CSPCo 8.1 7.5
I&M 516.1 481.4
KPCo - -
OPCo 39.5 36.5
PSO - -
SWEPCo - -
TCC 203.2 188.8
TNC - -
Rescission of EITF 98-10
In October 2002, the Emerging Issues Task Force of the FASB reached a
final consensus on Issue No. 02-3. See "New Accounting Pronouncements"
in Note 1 of the 2002 Annual Report (as updated by the Current report on
Form 8-K dated May 14, 2003) for further information.
SFAS 149 "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
On April 30, 2003, the FASB issued Statement No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" (SFAS
149). SFAS 149 amends SFAS 133 for certain decisions made by the FASB as
part of the Derivative Implementation Group process and to incorporate
clarifications of the definition of a derivative and which contracts
qualify as "normal purchase/normal sale." SFAS 149 also amends certain
other existing pronouncements. Except for certain provisions of SFAS 149
discussed below, SFAS 149 is effective for contracts entered into or
modified after June 30, 2003, and for hedging relationships designated
after June 30, 2003. The provisions of SFAS 149 relating to decisions
cleared by the FASB as part of the Derivative Implementation Group
process shall continue to be applied in accordance with their respective
effective dates. In addition, certain paragraphs of SFAS 149, which
relate to forward purchases and sales of when-issued securities or other
securities that do not yet exist, shall be applied to both existing
contracts and new contracts entered into after June 30, 2003. We are
currently assessing the impact of the adoption of SFAS 149.
SFAS 150 "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
SFAS 150 was effective for us on July 1, 2003. SFAS 150 is the result of
the first phase of the FASB's project to eliminate from the balance
sheet the "mezzanine" presentation of items with characteristics of both
liabilities and equity, so that no such items will be presented between
liabilities and equity.
SFAS 150 requires that the following three types of freestanding
financial instruments be reported as liabilities: (1) mandatorily
redeemable shares, (2) instruments other than shares that could require
the issuer to buy back some of its shares in exchange for cash or other
assets and (3) obligations that can be settled with shares, the monetary
value of which is either (a) fixed, (b) tied to the value of a variable
other than the issuer's shares, or (c) varies inversely with the value
of the issuer's shares. Measurement of these liabilities generally is to
be at fair value, with the payment or accrual of "dividends" and other
amounts to holders reported as interest cost. Upon adoption of the new
statement, any measurement change for these liabilities is to be
reported as the cumulative effect of a change in accounting principle.
We are currently assessing the impact of the adoption of SFAS 150.
Beginning with AEP's third quarter 2003 financial statements, $321
million ($136 million TCC, $110 million SWEPCo and $75 million PSO) of
certain subsidiary obligated, mandatorily redeemable, preferred
securities of subsidiary trusts holding solely junior subordinated
debentures of such subsidiaries, $83 million ($11 million APCo, $63
million I&M and $9 million OPCo) of mandatorily redeemable cumulative
preferred stock of subsidiaries, and $376 million (all AEP) of equity
unit senior notes, all of which are currently given mezzanine
presentation, are expected to be reclassified as liabilities on the
balance sheet. We are, however, still assessing the ultimate impact of
SFAS 150.
Future Accounting Changes
FASB's standard-setting process is ongoing. 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.
3. CUMULATIVE EFFECT OF ACCOUNTING CHANGES
---------------------------------------
SFAS 143, "Accounting for Asset Retirement Obligations" (see Note 2),
was effective on January 1, 2003. In the first quarter of 2003, AEP's
registrant subsidiaries recorded after-tax income related to the
recording of Asset Retirement Obligations in their respective Statements
of Operations as a cumulative effect of accounting change. See the
summary by registrant subsidiary of the cumulative effect of changes in
accounting principles recorded in the first quarter of 2003 for the
adoptions of SFAS 143 and EITF 02-3.
EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under
EITF 02-3, mark-to-market accounting is precluded for energy trading
contracts that are not derivatives pursuant to SFAS 133. The consensus
to rescind EITF 98-10 eliminated any basis for recognizing physical
inventories at fair value other than as provided by GAAP. The consensus
to rescind EITF 98-10 is effective for all new contracts entered into
(and physical inventory purchased) after October 25, 2002. The consensus
is effective for fiscal periods beginning after December 15, 2002, and
applies to all energy trading contracts that existed on or before
October 25, 2002 that remain in effect as of the date of implementation,
January 1, 2003. Effective January 2003, nonderivative energy contracts
entered into prior to October 25, 2002 are required to be accounted for
on a settlement basis and inventory is required to be presented at the
lower of cost or market. The effect of implementing this consensus is
reported as a cumulative effect of an accounting change. Such contracts
and inventory are accounted for at fair value through December 31, 2002.
Energy contracts that qualify as derivatives were accounted for at fair
value under SFAS 133. AEP's registrant subsidiaries have recorded
after-tax charges against net income as Accounting for Risk Management
Contracts in their respective Statements of Operations as Cumulative
Effect of Accounting Changes in the first quarter of 2003. This amount
will be recognized when the positions settle.
The following is a summary by registrant subsidiary of the cumulative
effect of changes in accounting principles recorded in the first quarter
of 2003 for the adoptions of SFAS 143 and EITF 02-3 (no effect on AEGCo
or PSO):
SFAS 143 Cumulative Effect EITF 02-3 Cumulative Effect
-------------------------- ---------------------------
Pre-tax After-tax Pre-tax After-tax
Income (Loss) Income (Loss) Income (Loss) Income (Loss)
------------- ------------- ------------- -------------
(in millions) (in millions)
APCo $128.3 $ 80.3 $ (4.7) $ (3.0)
CSPCo 49.0 29.3 (3.1) (2.0)
I&M - - (4.9) (3.2)
KPCo - - (1.7) (1.1)
OPCo 213.6 127.3 (4.2) (2.7)
SWEPCo 13.0 8.4 0.2 0.1
TCC - - 0.2 0.1
TNC 4.7 3.1 - -
4. GOODWILL AND OTHER INTANGIBLE ASSETS
------------------------------------
Goodwill
There continues to be no goodwill recorded at the AEP registrant
subsidiaries as of June 30, 2003.
Acquired Intangible Assets
The gross carrying amount, accumulated amortization and amortization
life by major asset class are shown in the following table:
June 30, 2003 December 31, 2002
----------------------------- ------------------------------
Gross Gross
Amortization Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------ -------- ------------ -------- ------------
(in millions)
Advanced royalties -
SWEPCo 10 $29.4 $6.2 $29.4 $4.7
Intangible asset amortization expense was $0.7 million for the three
months ended June 30, 2003 and June 30, 2002 and $1.5 million for the six
months ended June 30, 2003 and June 30, 2002. Estimated aggregate
amortization expense is $3.0 million per year in 2004 through 2009.
Intangible assets subject to amortization are recorded in Deferred
Charges in SWEPCo's Consolidated Balance Sheets.
5. RATE MATTERS
-----------
Fuel in SPP - Affecting SWEPCo and TNC
As discussed in Note 6 of the 2002 Annual Report (as updated by the
Current Report on Form 8-K dated May 14, 2003), in 2001, the PUCT delayed
the start of customer choice in the SPP area of Texas. In May 2003, the
PUCT ordered that competition would not begin in the SPP area before
January 1, 2007. The PUCT has ruled that TNC fuel factors in the SPP area
will be based upon the price-to-beat fuel factors offered by the retail
electric provider (REP) in the ERCOT portion of TNC's service territory.
TNC filed with the PUCT in 2002 to determine the most appropriate method
to reconcile fuel costs in TNC's SPP area. In April 2003, the PUCT issued
an order adopting the methodology proposed in TNC's filing, with
adjustments, for reconciling fuel costs in its SPP area. The adjustments
removed $3.71 per MWH from reconcilable fuel expense. This adjustment
will reduce revenues received from TNC's SPP customers by approximately
$400 thousand annually. These customers are now served by SWEPCo's REP.
TNC Fuel Reconciliation - Affecting TNC
In June 2002, TNC filed with the PUCT to reconcile fuel costs and 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 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. TNC's SPP customers will continue to be
subject to fuel reconciliations until competition begins in the SPP area.
The under-recovery balance at December 31, 2001 for TNC's service within
SPP was $0.7 million including interest. As noted above, TNC's SPP
customers are now being served by SWEPCo's REP.
In March 2003, the Administrative Law Judges (ALJ) in this proceeding
filed their Proposal for Decision (PFD). The PFD recommends that TNC's
under-recovered retail fuel balance be reduced by approximately $12.5
million. In March 2003, TNC established a reserve of $13 million,
including interest, based on the PFD's recommendations. On April 22,
2003, TNC and intervenors in this proceeding filed exceptions to the PFD.
On May 28, 2003, the PUCT remanded TNC's final fuel reconciliation to the
ALJ to consider several issues. Two of these remand issues could result
in additional disallowances. The issues are the sharing of off-system
sales margins from AEP's trading activities with customers through the
fuel factor 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.
TNC made a filing on July 15, 2003 addressing the remand issues. The PUCT
is proposing that the sharing of off-system sales margins should continue
beyond the termination of the fuel factor. 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. 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 and that after a
more thorough review of the evidence it is only reasonably possible that
the PUCT will determine after the remand proceeding that TNC should share
margins after the end of the Texas fuel factor. Due to a provision
established in the first quarter, the resolution of the fuel factor issue
should have an immaterial impact on results of operations. However, the
decision of the PUCT could result in additional income reductions for
these issues. It is presently expected that the ALJ's PFD and the PUCT's
final decision of these remanded issues will occur in late 2003 or early
2004.
In February 2002, TNC received a final order from the PUCT in a fuel
reconciliation covering the period July 1997 - June 2000 and reflected
the order in its financial statements. This final order had been appealed
to the Travis County District Court. In May 2003, the District Court
upheld the PUCT's final order. The plaintiffs appealed the District
Court's decision to the Third Court of Appeals.
TCC Fuel Reconciliation - Affecting TCC
In December 2002, TCC filed with the PUCT to reconcile fuel costs and to
defer its over-recovery of fuel for inclusion in the 2004 true-up
proceeding. This reconciliation for the period of July 1998 through
December 2001 will be the final fuel reconciliation. 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. Recommendations from intervening
parties were received in April 2003 and hearings were held in May 2003.
Intervening parties have recommended disallowances totaling $170 million.
In March 2003, the ALJ hearing the TNC final fuel reconciliation,
discussed above, issued a PFD in the TNC proceeding. Various issues
addressed in TNC's proceeding may also be applicable to TCC's proceeding.
Consequently, TCC established a reserve for potential adverse rulings of
$27 million during the first quarter of 2003. Based upon the PUCT's
remand of certain TNC issues, TCC established an additional reserve of $9
million in the second quarter of 2003. An adverse ruling from the PUCT in
excess of the reserves 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 6
"Customer Choice and Industry Restructuring".
SWEPCo Fuel Reconciliation - Affecting SWEPCo
In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs. This
reconciliation covers the period of January 2000 through December 2002.
At December 31, 2002, SWEPCo's filing detailed a $2.2 million
over-recovery balance including interest. During the reconciliation
period, SWEPCo incurred $434.8 million of eligible fuel expense. An
adverse ruling from the PUCT could have a material impact on future
results of operations, cash flows and financial condition.
ERCOT Price-to-Beat (PTB) Fuel Factor Appeal - Affecting TCC and TNC
Several parties including the Office of Public Utility Counsel (OPC) and
cities served by both TCC and TNC appealed the PUCT's December 2001
orders establishing initial PTB fuel factors for Mutual Energy CPL and
Mutual Energy WTU. On June 25, 2003, the District Court ruled in both
appeals. The Court ruled in the Mutual Energy WTU case that the PUCT
lacked sufficient evidence to include unaccounted for energy in the fuel
factor, erred in including unaccounted for energy in the PTB rate based
on its treatment in other proceedings and that the PUCT had improperly
shifted the burden of proof from the utility to the intervening parties
in not adjusting projected generation requirements for loss of load. The
Court upheld the initial PTB orders on all other issues. In the Mutual
Energy CPL proceeding, the Court ruled that the PUCT should have adjusted
projected generation requirements for the loss of load due to retail
competition. The Court remanded the cases to the PUCT for further
proceedings consistent with its ruling. The amount of unaccounted for
energy built into the PTB fuel factors was approximately $2.7 million for
Mutual Energy WTU. At this time, management is unable to estimate the
potential financial impact related to the loss of load issue. Management
will appeal the District Court decisions and believes, based on the
advice of counsel, that the PUCT's original decision will ultimately be
upheld. If the District Court's decisions are ultimately upheld, the PUCT
could reduce the PTB fuel factors charged to retail customers in 2002 and
2003 resulting in an adverse effect on future results of operations and
cash flows.
Unbundled Cost of Service (UCOS) Appeal - Affecting TCC
TCC placed new transmission and distribution rates into effect as of
January 1, 2002 based upon an order issued by the PUCT resulting from an
UCOS proceeding. TCC requested and received approval of wholesale
transmission rates determined in the UCOS proceeding with the FERC. The
UCOS proceeding set the regulated wires rates to be effective when retail
electric competition began. Regulated delivery charges include the retail
transmission and distribution charge, a system benefit fund fee, a
nuclear decommissioning fund charge, a municipal franchise fee and a
transition charge associated with securitization of regulatory assets.
Certain rulings of the PUCT in the UCOS proceeding, including the initial
determination of stranded costs, the commencement of TCC's excess
earnings refund, regulatory treatment of nuclear insurance and
distribution rates charged municipal customers, were appealed to the
Travis County District Court by TCC and other parties to the proceeding.
The District Court issued a decision on June 16, 2003 upholding the
PUCT's UCOS order with one exception. The Court ruled that the refund of
the 1999 - 2001 excess earnings solely as a credit to non-bypassable
transmission and distribution rates charged to retail electric providers
(REP) discriminates against residential and small commercial customers
and is unlawful. The distribution rate credit began in January 2002. This
decision could potentially affect the PTB rates charged by the AEP REP
(Mutual Energy CPL). Mutual Energy CPL was a subsidiary of AEP until
December 23, 2002 when it was sold to Centrica. Management estimates that
the effect of reducing the PTB rates for the period prior to the sale is
approximately $11 million pre-tax. Management has appealed this decision
and, based on advise of counsel, believes that it will ultimately prevail
on appeal. If the District Court's decision is ultimately upheld on
appeal, it could have an adverse effect on future results of operations
and cash flows.
McAllen Rate Review - Affecting TCC
On June 26, 2003, the City of McAllen requested that TCC provide
justification showing that its transmission and distribution rates should
not be reduced. Other municipalities served by TCC have passed similar
rate review resolutions. In Texas, municipalities have original
jurisdiction over rates of electric utilities within their municipal
limits. Under Texas law, TCC has a minimum of 120 days to provide support
for its rates to the municipalities. TCC has the right to appeal any rate
change by the municipalities to the PUCT. Pursuant to an agreement with
the cities, TCC will file the requested support for its rates with both
the cities and the PUCT on November 3, 2003. Management believes that a
rate reduction is not justified.
Louisiana Fuel Audit - Affecting SWEPCO
As a result of complaints filed by customers, the LPSC is performing an
audit of SWEPCo's fuel rates. Five SWEPCo customers filed a suit in the
Caddo Parish District Court in January 2003 and filed a complaint with
the LPSC. The customers claim that SWEPCo has overcharged them for fuel
costs since 1975. Management believes that SWEPCo's fuel rates prior to
1999 were proper and have been approved by the LPSC. If the LPSC or the
Court rules against SWEPCo, it could have an adverse impact on results of
operations and cash flows.
FERC Wholesale Fuel Complaints - Affecting TNC
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), certain TNC wholesale customers filed a
complaint with FERC alleging that TNC had overcharged them through the
fuel adjustment clause for certain purchased power costs since 1997.
Negotiations to settle the complaint and update the contracts have
resulted in new contracts. Consequently, an offer of settlement was filed
at FERC in June 2003 regarding the fuel complaint and new contracts.
Management is unable to predict whether FERC will approve this offer of
settlement which is not expected to have a significant impact on TNC's
financial condition. In March 2002, TNC recorded a provision for refund
of $2.2 million before income taxes. TNC anticipates that the provision
for refund will be adequate to cover the financial implications resulting
from these new contracts. Should FERC fail to approve the settlement and
new contracts, the actual refund and final resolution of this matter
could differ materially from the provision and may have a negative impact
on future results of operations, cash flows and financial condition.
Environmental Surcharge Filing - Affecting KPCo
In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff (annual revenue increase of approximately $21 million)
to recover the cost of emissions control equipment being installed at Big
Sandy Plant. See NOx Reductions in Note 7.
In March 2003, the KPSC granted approximately $18 million of the request.
Annual rate relief of $1.7 million was effective in May 2003 and an
additional $16.2 million was effective in July 2003. The recovery of such
amounts is intended to offset KPCo's cost of compliance with the Clean
Air Act.
PSO Rate Review - Affecting PSO
In February 2003, the Director of the Oklahoma Corporation Commission
(OCC) filed an application requiring PSO to file all documents necessary
for a general rate review before August 1, 2003. The required date to
file the case was subsequently changed to October 31, 2003. Management is
unable to predict the ultimate effect of this review on PSO's rates.
PSO Fuel and Purchased Power - Affecting PSO
As discussed in Note 6 of the 2002 Annual Report (as updated by the
Current Report on Form 8-K dated May 14, 2003), PSO had a $44 million
under-recovery of fuel costs resulting from a reallocation of purchased
power costs for periods prior to January 1, 2002. On July 23, 2003, PSO
filed with the OCC seeking recovery of the $44 million over an eighteen
month time period. A hearing has been scheduled for October 7, 2003. If
the OCC does not permit recovery, there will be an adverse effect on
results of operations, cash flows and possibly financial condition.
Virginia Fuel Factor Filing - Affecting APCo
APCo filed with the Virginia SCC to reduce its fuel factor effective
August 1, 2003. The requested fuel rate reduction would be effective for
17 months and is estimated to reduce revenues by $36 million. By order
dated July 23, 2003, the Virginia SCC approved APCo's requested fuel
factor reduction on an interim basis, subject to further investigation.
This fuel factor adjustment will reduce cash flows without impacting
results of operations as any over-recovery of fuel costs would be
deferred as a regulatory liability.
FERC Long-term Contracts - Affecting AEP East and AEP West companies
In September 2002, the FERC voted to hold hearings to consider requests
from certain wholesale customers located in Nevada and Washington to
break long-term contracts which they allege are "high-priced". At issue
are long-term contracts entered during the California energy price spike
in 2000 and 2001. The complaints allege that AEP sold power at unjust and
unreasonable prices. The FERC delayed hearings to allow the parties to
hold settlement discussions. In January 2003, the FERC settlement judge
assigned to the case indicated that the parties' settlement efforts were
not progressing and he recommended that the complaint be placed back on
the schedule for a hearing. In February 2003, AEP and one of the
customers agreed to terminate their contract. The customer withdrew its
FERC complaint and paid $59 million to AEP. As a result of the contract
termination, AEP reversed $69 million of unrealized mark-to-market gains
previously recorded, resulting in a $10 million pre-tax loss.
In a similar complaint, a FERC administrative law judge (ALJ) ruled in
favor of AEP and dismissed, in December 2002, a complaint filed by two
Nevada utilities. In 2000 and 2001, AEP agreed to sell power to the
utilities for future delivery. In late 2001, the utilities filed
complaints that the prices for power supplied under those contracts
should be lowered because the market for power was allegedly
dysfunctional at the time such contracts were consummated. The ALJ
rejected the utilities' complaint, held that the markets for future
delivery were not dysfunctional, and that the utilities had failed to
demonstrate that the public interest required that changes be made to the
contracts. The ALJ's order is preliminary and is subject to review by the
FERC. At a hearing held in April 2003, the utilities asked FERC to void
the long-term contracts. The FERC will likely rule on the ALJ's order in
2003. Management is unable to predict the outcome of these proceedings or
their impact on future results of operations.
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). On July 2, 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 $22 million of RTO formation
and integration costs and related carrying charges (APCo-$6 million,
CSPCo-$3 million, I&M-$5 million, KPCo-$1 million, OPCo-$7 million)
through June 30, 2003. As a result of the subsequent delay in the
integration of AEP's East transmission system into PJM, FERC declined to
rule, at this time, 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 will apply for permission to transfer the deferred
formation/integration costs to a regulatory asset prior to integration
with PJM.
In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO until after June 30, 2004 and only
then with the approval of the Virginia SCC. In the second quarter of
2003, the KPSC denied KPCo's request that they approve our joining PJM
based in part on a lack of evidence that it would benefit Kentucky retail
customers. Management intends to seek a rehearing in Kentucky. Management
does not expect the integration with PJM to occur prior to June 30, 2004.
In its July 2 order, FERC indicated that it would review the deferred
costs for prudency 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's East companies' portion
of the OATT at the time they join PJM. Presently, retail rates are frozen
or capped and cannot be increased for retail customers of CSPCo, I&M and
OPCo. AEP intends to apply 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. 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. Management intends to seek
recovery of the deferred RTO formation/integration costs. 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.
FERC Order on Regional Through and Out Rates (RTOR) - Affecting APCo,
CSPCo, I&M, KPCo and OPCo
On July 23, 2003, the FERC issued an order directing PJM and the Midwest
ISO to make compliance filings for their respective Open Access
Transmission Tariffs to eliminate, by November 1, 2003, the Regional
Through and Out Rates (RTOR) on transactions where the energy is
delivered within the Midwest ISO and PJM regions. The elimination of the
RTORs 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 RTORs.
The FERC also found that the through and out 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 Midwest
ISO/PJM regions. FERC has initiated an investigation and hearing in
regard to these rates. AEP will make a filing with the FERC supporting
the justness and reasonableness of its rates by August 15, 2003.
Management at this time is unable to predict the ultimate outcome of this
investigation, or the impact on the results of operations and cash flows.
6. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
------------------------------------------
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), retail customer choice began in four of
the eleven state retail jurisdictions (Michigan, Ohio, Texas and
Virginia) in which the AEP domestic electric utility companies operate.
The following paragraphs discuss significant events occurring in 2003
related to customer choice and industry restructuring.
Ohio Restructuring - Affecting CSPCo and OPCo
On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy
Users-Ohio and American Municipal Power-Ohio filed a complaint with the
PUCO alleging that CSPCo and OPCo have violated the PUCO's orders
regarding implementation of their transition plan and violated other
applicable law by failing to participate in an RTO.
The complainants seek, among other relief, an order from the PUCO:
o suspending collection of transition charges by CSPCo and
OPCo until transfer of control of their transmission assets
has occurred
o pricing standard offer electric generation effective
January 1, 2006 at the market price used by CSPCo and OPCo
in their 1999 transition plan filings to estimate transition
costs and
o imposing a $25,000 per company forfeiture for each day AEP
fails to comply with its commitment to transfer control of
transmission assets to an RTO
Due to the FERC's reversal of its previous approval of our RTO filings
and state legislative and regulatory developments, CSPCo and OPCo have
been delayed in the implementation of their RTO participation plans. We
continue to pursue integration of CSPCo, OPCo and other AEP East
companies into PJM. In this regard on December 19, 2002, CSPCo and OPCo
filed an application with the PUCO for approval of the transfer of
functional control over certain of their transmission facilities to PJM.
In February 2003, the PUCO consolidated the June complaint with our
December application. CSPCo's and OPCo's motion to dismiss the complaint
has been denied by the PUCO and the PUCO affirmed that ruling in
rehearing. All further action in the consolidated case has been stayed
"until more clarity is achieved regarding matters pending at the FERC
and elsewhere". Management is unable to predict the timing of the AEP's
East companies' participation in PJM, or the outcome of these
proceedings before the PUCO.
On March 20, 2003, the PUCO commenced a statutorily-required
investigation concerning the desirability, feasibility and timing of
declaring retail ancillary, metering or billing and collection service
supplied to customers within the certified territories of electric
utilities a competitive retail electric service. The PUCO sent out a
list of questions and set June 6, 2003 and July 7, 2003, as the dates
for initial responses and replies, respectively. CSPCo and OPCo filed
comments and responses in compliance with the PUCO's schedule.
Management is unable to predict the timing or the outcome of this
proceeding.
The Ohio Act provides for a Development Period during which retail
customers can choose their electric power suppliers or have the
protection of Default Service at frozen generation rates from the
incumbent utility. The Development Period began on January 1, 2001 and
will terminate no later than December 31, 2005, but the PUCO may
terminate the Development Period 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 Development Period, 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 have the
protection of Default Service which must be offered by the incumbent
utility at market rates. The PUCO has circulated a draft of proposed
rules but has not yet identified the method by which it will determine
market rates for Default Service following the Development Period.
As provided in the stipulation agreement approved by the PUCO, CSPCo and
OPCo are deferring customer choice implementation costs 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. CSPCo has deferred $10 million and OPCo has deferred $12
million of such costs. Recovery of these regulatory assets will be
subject to PUCO review in each company's next Ohio distribution rate
filings which will not occur until after 2008 for CSPCo and 2007 for
OPCo. Management believes that the amounts deferred represent prudently
incurred customer choice implementation costs and 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
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), on January 1, 2002, customer choice of
electricity supplier began in the ERCOT area of Texas. Customer choice
has been delayed in other areas of Texas including the SPP area in which
SWEPCo operates. In May 2003, the PUCT approved a stipulation that
delays competition in the SPP area until at least January 1, 2007.
A 2004 true-up proceeding will determine the amount of stranded costs,
final fuel balance, net regulatory assets, certain environmental costs,
accumulated excess earnings, excess of price-to-beat revenues over
market prices subject to certain conditions and limitations (Retail
clawback), a true-up of the power costs used in the PUCT's ECOM model
for 2002 and 2003 to reflect actual market prices determined through
legislatively-mandated capacity auctions (Wholesale capacity auction
true-up) and other restructuring issues.
The Texas Legislation allows for several alternative methods to be used
to value stranded costs in the final 2004 true-up proceeding including
the sale or exchange of generation assets, stock valuation or the use of
an ECOM model. Only TCC has stranded costs under the Texas Legislation.
In late 2002, TCC decided to obtain a market value of generating assets
for purposes of determining stranded costs for the 2004 true-up
proceeding and filed a plan of divestiture with the PUCT seeking
approval of a sales process for all of its generating facilities. Such
sales would quantify the actual stranded costs. The amount of stranded
costs under this market valuation methodology will be the amount by
which net book value of TCC's generating 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. The filing included a request for the PUCT to issue a
declaratory order that TCC's 25.2% ownership interest in its nuclear
plant, STP, can be sold to value stranded costs. Intervenors to this
proceeding, including the PUCT Staff, made filings to dismiss TCC's
filing claiming that the PUCT does not have the authority to issue a
declaratory order. The intervenors also argued that the proper time to
address the sales process is after the plants are sold during the 2004
true-up proceeding. Since the bidding process is not expected to be
completed before mid-2004, TCC requested that the 2004 true-up
proceeding be scheduled after completion of the divestiture of the
generating assets.
In March 2003, the PUCT dismissed TCC's divestiture filing, determining
that it was more appropriate to address the nuclear asset stranded costs
valuation in a rulemaking proceeding. The PUCT approved a rule, in May
2003, that allows the value obtained by selling nuclear assets to be
used in determining stranded costs. Since the PUCT also dismissed the
request to certify the proposed divestiture plan, the divestiture plan
utilized by TCC will still be subject to a review in the 2004 true-up
proceedings. The PUCT adopted a rule regarding the timing of the 2004
true-up proceedings scheduling TNC's filing in May 2004 and TCC's filing
in September 2004.
Texas Legislation also requires that electric utilities and their
affiliated power generation companies (PGC) sell at auction in 2002 and
2003 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 and liquidity. Actual
market power prices received in the state mandated auctions will replace
the PUCT's earlier estimates of those market prices used in the ECOM
model to calculate the wholesale capacity auction true-up adjustment for
TCC for the 2004 true-up proceeding.
The decision to determine stranded costs by selling TCC's generating
plants and the expectation that the sales price would produce a
significant loss/stranded costs instead of using the PUCT's ECOM model
estimates, enabled TCC to record in 2002 a $262 million regulatory asset
and related revenues which represents the quantifiable amount of the
wholesale capacity auction true-up for the year 2002. Through June 30,
2003, TCC recorded an additional $108 million regulatory asset and
related revenues for the wholesale capacity auction true-up. Prior to
the decision to pursue a sale of TCC's generating assets, the PUCT's
ECOM estimate prohibited the recognition of the regulatory assets and
revenues as they can not be recovered unless there are stranded costs.
As discussed above, a defined process is required in order to determine
the amount of stranded costs related to generation facilities for the
2004 true-up proceedings.
In June 2003, the PUCT Staff proposed a refinement in the calculation of
the wholesale capacity auction true-up. The Staff's proposed methodology
could result in a material change in the amount of the wholesale
capacity auction true-up for 2002 and 2003. The PUCT Staff's proposed
true-up filing package has been published for comments that are due in
September. A final true-up filing package is expected to be adopted by
the end of 2003.
When the divestiture and the 2004 true-up proceeding are completed, TCC
can securitize stranded costs that are in excess of current securitized
amounts. The annual costs of securitization will be recovered through a
non-bypassable rate surcharge by the regulated transmission and
distribution (T&D) utility over the life of the securitization bonds.
Any stranded costs and other true-up amounts not recovered through the
sale of securitization bonds may be recovered through a separate
non-bypassable competition transition charge to T&D utility customers.
In the event TCC and TNC are unable, after the 2004 true-up proceeding,
to recover all or a portion of their generation-related regulatory
assets, unrecovered fuel balances, stranded costs, other true-up
adjustments and other restructuring related costs, it could have a
material adverse effect on results of operations, cash flows and
possibly financial condition.
Arkansas Restructuring - Affecting SWEPCo
In February 2003, Arkansas repealed customer choice legislation
originally enacted in 1999. Consequently, SWEPCo's Arkansas operations
reapplied SFAS 71 regulatory accounting which had been discontinued in
1999. The reapplication of SFAS 71 had an insignificant effect on
results of operations for the first six months of 2003. As a result of
reapplying SFAS 71, derivative contract gains/losses for transactions
within AEP's traditional marketing area allocated to Arkansas will not
affect income until settled. That is, such positions will be recorded on
the balance sheet as either a regulatory asset or liability until
realized.
West Virginia Restructuring - Affecting APCo
APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the
first quarter of 2003 after new developments during the quarter prompted
an analysis of the probability of restructuring becoming effective.
In 2000, the WVPSC issued an order approving an electricity
restructuring plan, which the WV Legislature approved by joint
resolution. The joint resolution provided that the WVPSC could not
implement the plan until the WV legislature made tax law changes
necessary to preserve the revenues of state and local governments.
In the 2001 and 2002 legislative sessions, the WV Legislature failed to
enact the required legislation that would allow the WVPSC to implement
the restructuring plan. Due to this lack of legislative activity, the
WVPSC closed two proceedings related to electricity restructuring during
the summer of 2002.
In the 2003 legislative session, the WV Legislature failed to enact the
required tax legislation. Also, a March 2003 WV Legislative Bill
clarified the jurisdiction of the WVPSC over electric generation
facilities in WV. In March 2003, APCo's outside counsel advised us that
restructuring in West Virginia was no longer probable and confirmed
facts relating to the WVPSC's jurisdiction and rate authority over
APCo's WV generation. APCo has concluded that deregulation of the WV
generation business is no longer probable and operations in WV meet the
requirements to reapply SFAS 71.
The result of reapplying SFAS 71 in WV had an insignificant effect on
results of operations during the first six months of 2003. As a result,
derivative contract gains/losses related to transactions within AEP's
traditional marketing area allocated to WV will not affect income until
settled. That is, such positions will be recorded on the balance sheet
as either a regulatory asset or liability until realized. Positions
outside AEP's traditional marketing area will continue to be
marked-to-market.
7. COMMITMENTS AND CONTINGENCIES
-----------------------------
Nuclear Plant Outages - Affecting I&M and TCC
In April 2003, engineers at STP, during inspections conducted regularly
as part of refueling outages, found wall cracks in two bottom mounted
instrument guide tubes of STP Unit 1. These cracks have been repaired
and the unit is expected to return to service in late summer. TCC's
share of the direct cost of repair was approximately $6 million through
June 30, 2003. STP officials are working closely with the NRC to safely
return the unit to service. We have commitments to provide power to
customers during the outage. Therefore, we will be subject to
fluctuations in the market prices of electricity and purchased
replacement energy could be a significant cost.
In April 2003, both units of I&M's Cook Plant were taken offline due to
an influx of fish in the plant's cooling water system which caused a
reduction in cooling water to essential plant equipment. After repair of
damage caused by the fish intrusion, Cook Plant Unit 1 returned to
service in May and Unit 2 returned to service in June following
completion of a scheduled refueling outage.
Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo,
I&M, and OPCo
As discussed in Note 9 of the Combined Notes to Financial Statements in
the 2002 Annual Report (as updated by the Current Report on Form 8-K
dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings", AEPSC, APCo, CSPCo, I&M, and OPCo have been
involved in litigation regarding generating plant emissions under the
Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo,
I&M, OPCo and eleven unaffiliated utilities modified certain units at
coal-fired generating plants in violation of the Clean Air Act. Federal
EPA filed complaints against AEP subsidiaries in U.S. District Court for
the Southern District of Ohio. A separate lawsuit initiated by certain
special interest groups was consolidated with the Federal EPA case. The
alleged modification of the generating units occurred over a 20 year
period.
Under the Clean Air Act, 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 Clean Air Act
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.
Management believes its maintenance, repair and replacement activities
were in conformity with the Clean Air Act and intends to vigorously
pursue its defense.
Management is unable to estimate the loss or range of loss related to
the contingent liability for civil penalties under the Clear Air Act
proceedings and 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. In the event 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 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.
NOx Reductions - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo,
SWEPCo and TCC
Federal EPA issued a NOx Rule requiring substantial reductions in NOx
emissions in a number of eastern states, including certain states in
which the AEP System's generating plants are located. The NOx Rule has
been upheld on appeal. The compliance date for the NOx Rule is May 31,
2004.
In 2000, Federal EPA also adopted a revised rule (the Section 126 Rule)
granting petitions filed by certain northeastern states under the Clean
Air Act. The rule imposes emissions reduction requirements comparable to
the NOx Rule beginning May 1, 2003, for most of our coal-fired
generating units. Affected utilities, including certain AEP operating
companies, petitioned the D.C. Circuit Court to review the Section 126
Rule.
After review, the D.C. Circuit Court instructed Federal EPA to justify
the methods it used to allocate allowances and project growth for both
the NOx Rule and the Section 126 Rule. AEP subsidiaries and other
utilities requested that the D.C. Circuit Court vacate the Section 126
Rule or suspend its May 2003 compliance date. In 2001, the D.C. Circuit
Court issued an order tolling the compliance schedule until Federal EPA
responds to the Court's remand. On April 30, 2002, Federal EPA announced
that May 31, 2004 is the compliance date for the Section 126 Rule.
Federal EPA published a notice in the Federal Register on May 1, 2002
advising that no changes in the growth factors used to set the NOx
budgets were warranted. In June 2002, AEP subsidiaries joined other
utilities and industrial organizations in seeking a review of Federal
EPA's actions in the D.C. Circuit Court. This action is pending.
In 2000, the Texas Commission on Environmental Quality adopted rules
requiring significant reductions in NOx emissions from utility sources,
including TCC and SWEPCo. The compliance requirements began in May 2003
for TCC and begin in May 2005 for SWEPCo.
We are installing a variety of emission control technologies to reduce
NOx emissions to comply with the applicable state and Federal NOx
requirements. This includes selective catalytic reduction (SCR)
technology on certain units and non-SCR technologies on a larger number
of units. During 2001 SCR technology commenced operations on OPCo's
Gavin Plant. Installation of SCR technology on Amos and Mountaineer
plants was completed and commenced operation in May 2002. In May 2003,
SCR technology installed at Big Sandy and Cardinal plants commenced
operation. Construction of SCR technology at certain other AEP
generating units continues. Non-SCR technologies have been installed and
commenced operation on a number of units across the AEP System and
additional units will be equipped with these technologies.
The NOx compliance plan is a dynamic plan that is continually reviewed
and revised as new information becomes available on the performance of
installed technologies and the cost of planned technologies. Certain
compliance steps may or may not be necessary as a result of this new
information. Consequently, the plan has a range of possible outcomes.
Our current estimates indicate that AEP's compliance with the NOx Rule,
the Texas Commission on Environmental Quality rule and the Section 126
Rule could result in required capital expenditures in the range of $1.3
billion to $1.7 billion, of which $976 million has been spent through
June 30, 2003. Estimated compliance cost ranges and amounts spent by
registrant subsidiaries are as follows:
Estimated Amount
Compliance Costs Spent
---------------- -----
(in millions)
AEGCo $ 28 $ 6
APCo 462 261
CSPCo 87 61
I&M 39 9
KPCo 180 177
OPCo 524-853 427
SWEPCo 35 23
TCC 5 5
Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the estimates
depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless any capital and operating costs for
additional pollution control equipment are recovered from customers,
they will have an adverse effect on future results of operations, cash
flows and possibly financial condition.
Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC
Texas Commercial Energy, LLP (TCE), a Texas REP, has filed a lawsuit in
federal District Court in Corpus Christi, Texas against AEP and four AEP
subsidiaries, certain unaffiliated energy companies and ERCOT. The
action alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made
against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price
spikes requiring TCE to post additional collateral and ultimately forced
it into bankruptcy when it was unable to raise prices to its customers
due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary
damages and court costs. Management believes that the claims against AEP
and its subsidiaries are without merit and intends to vigorously defend
against the claims.
FERC Proposed Standard Market Design - Affecting AEP System
In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking which sought to standardize the structure and
operation of wholesale electricity markets across the country. Key
elements of FERC's proposal included standard rules and processes for
all users of the electricity transmission grid, new transmission rules
and policies, and the creation of certain markets to be operated by
independent administrators of the grid in all regions. The FERC issued a
white paper on the proposal in April 2003, in response to the numerous
comments FERC received on its proposal. Until the rule is finalized,
management cannot predict its effect on cash flows and results of
operations.
FERC Proposed Security Standards - Affecting AEP System
As part of the SMD proposed rulemaking, in July 2002, FERC published for
comment proposed security standards. These standards were intended to
ensure that all market participants would have a basic security program
that would effectively protect the electric grid and related market
activities. As proposed, these standards would apply to AEP's power
transmission systems, distribution systems and related areas of
business. The proposed standards have not been adopted. Subsequently, in
2002, the North American Electric Reliability Council (NERC), with
FERC's support, developed a new set of standards to address industry
compliance. These new standards closely parallel the initial, proposed
FERC standards in both content and compliance time frames, and were
approved by the NERC ballot body in June of 2003. AEP is developing
financial requirements for security implementation and compliance with
these NERC standards. Since these financial requirements are not yet
determined, management cannot predict the impacts of such standards on
future results of operations and cash flows.
8. GUARANTEES
----------
In November 2002, the FASB issued FIN 45 which clarifies the accounting
to recognize a liability related to issuing a guarantee, as well as
additional disclosures of guarantees. This new guidance is an
interpretation of SFAS 5, 57, and 107 and a rescission of FIN 34. The
initial recognition and initial measurement provisions of FIN 45 were
effective on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements of FIN 45 were effective
for financial statements of interim or annual periods ending after
December 15, 2002.
There are no liabilities recorded for any guarantees entered into by
AEP's registrant subsidiaries in accordance with FIN 45 as these
guarantees were entered into prior to December 31, 2002 or have
immaterial values which were not recorded. There is no collateral held
in relation to these guarantees and there is no recourse to third
parties in the event these guarantees are drawn.
Certain AEP subsidiaries have entered into standby letters of credit
(LOC) with third parties. These LOCs cover gas and electricity trading
contracts, construction contracts, insurance programs, security
deposits, debt service reserves, drilling funds and credit enhancements
for issued bonds. All of these LOCs were issued by an AEP subsidiary in
the subsidiaries' ordinary course of business. TCC issued an LOC for
credit enhancement of issued bonds. At June 30, 2003, the maximum future
payments of all the LOCs are approximately $163 million with maturities
ranging from July 2003 to January 2011. TCC's LOC was for approximately
$40.9 million with a maturity date of November 2003. Since AEP is the
parent to all these subsidiaries, it holds all assets of the
subsidiaries as collateral. There is no recourse to third parties in the
event these letters of credit are drawn.
The following AEP subsidiaries have entered into guarantees of third-
party obligations:
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 a revolving credit
agreement, 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 $61 million with maturity dates
ranging from June 2005 to February 2012.
As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining, SWEPCo has agreed to provide
guarantees of mine reclamation in the amount of approximately $85
million. Since SWEPCo uses self-bonding, the guarantee provides for
SWEPCo to commit to use its resources to complete the reclamation in the
event the work is not completed by a third party miner. At June 30,
2003, 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.
It is reasonably possible that due to the guarantees and contracts in
place with Sabine that SWEPCo will consolidate Sabine in the third
quarter of 2003, as a result of the issuance of FIN 46. Upon
consolidation, SWEPCo would record the assets, liabilities, depreciation
expense, minority interest and debt interest expense of Sabine. SWEPCo
would eliminate expenses associated with the mining contract against
Sabine's revenues.
See Note 11 "Leases" for disclosure of lease residual value guarantees.
AEP and its subsidiaries enter 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,
AEP's registrant subsidiaries' exposure generally does not exceed the
sale price. AEP's registrant subsidiaries cannot estimate the maximum
potential exposure for any of these indemnifications entered prior to
December 31, 2002 due to the uncertainty of future events. In the first
six months of 2003, AEP's 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 during
the first six months of 2003. There are no liabilities recorded for any
indemnifications entered prior to December 31, 2002.
AEP and its subsidiaries lease certain equipment under a master
operating lease. Under the lease agreement, the lessor is guaranteed to
receive up to 87% of the unamortized balance of the equipment at the end
of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, we have
committed to pay the difference between the fair market value and the
unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At June 30, 2003, AEP's maximum potential loss for
these lease agreements was approximately $27 million assuming the fair
market value of the equipment is zero at the end of the lease term. The
maximum potential loss by registrant is as follows:
Maximum Potential Loss
Subsidiary (in millions)
---------- ----------------------
APCo $ 1
CSPCo 1
I&M 2
KPCo 1
OPCo 3
PSO 3
SWEPCo 3
TCC 6
TNC 2
Other AEP Subsidiaries 5
---
Total AEP $27
===
9. SUSTAINED EARNINGS IMPROVEMENT INITIATIVE
-----------------------------------------
In response to difficult conditions in our business, a Sustained
Earnings Improvement (SEI) initiative was undertaken company-wide in the
fourth quarter of 2002, as a cost-saving and revenue-building effort to
build long-term earnings growth. Termination benefits expense relating
to terminated employees was recorded in the fourth quarter of 2002. The
termination benefits expense was classified as Other Operation expense
on the statements of operations. No additional termination benefits
expense related to the SEI initiative was recorded during the first and
second quarters of 2003, and significantly all SEI related payments have
been made as of June 30, 2003.
See Note 11 "Sustained Earnings Improvement Initiative" in our 2002
Annual Report (as updated by the Current Report on Form 8-K dated May
14, 2003) for further information on expenses recorded by registrant
subsidiary during the fourth quarter 2002 related to the SEI initiative.
10. 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.
11. LEASES
------
OPCo has entered into an agreement with JMG Funding LLP (JMG), an
unrelated unconsolidated special purpose entity. JMG has a capital
structure of which 3% is equity from investors with no relationship to
AEP or any of its subsidiaries and 97% is debt from pollution control
bonds and other bonds. JMG was formed to design, construct and lease the
Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber
and leases it to OPCo. The lease is accounted for as an operating lease.
Payments under the operating lease are based on JMG's cost of financing
(both debt and equity) and include an amortization component plus the
cost of administration. OPCo and AEP do not have an ownership interest
in JMG and do not guarantee JMG's debt.
At any time during the lease, OPCo has the option to purchase the Gavin
Scrubber for the greater of its fair market value or adjusted
acquisition cost (equal to the unamortized debt and equity of JMG) or
sell the Gavin Scrubber. The initial 15-year lease term is
non-cancelable. At the end of the initial term, OPCo can renew the
lease, purchase the Gavin Scrubber (terms previously mentioned), or sell
the Gavin Scrubber. In case of a sale at less than the adjusted
acquisition cost, OPCo must pay the difference to JMG.
The use of JMG allows OPCo to enter into an operating lease while
keeping the tax benefits otherwise associated with a capital lease. As
of June 30, 2003, AEP has determined that OPCo will consolidate JMG in
the third quarter of 2003 as a result of the issuance of FIN 46. Upon
consolidation, OPCo will record the assets, liabilities, depreciation
expense, minority interest and debt interest expense of JMG. OPCo will
eliminate operating lease expense against JMG's rental revenues. As of
June 30, 2003, the Company is still reviewing the impact of the
consolidation, but will have to record the cumulative effect (net of
tax) due to a change in accounting principle. OPCo's maximum exposure to
loss as a result of its involvement with JMG is approximately $460
million of outstanding debt and equity of JMG as of June 30, 2003.
On March 31, 2003, OPCo made a prepayment of $90 million under this
operating lease structure. AEP recognizes lease expense on a
straight-line basis over the remaining lease term, in accordance with
SFAS 13 "Accounting for Leases." The asset will be amortized over the
remaining lease term, which ends in the first quarter of 2010.
12. FINANCING AND RELATED ACTIVITIES
--------------------------------
Long-term debt and other securities issuances and retirements during the
first six months of 2003 were:
Type Principal Interest Due
Company of Debt Amount Rate Date
------- ------- ----------- -------- ----
Issuances (in millions) (%)
---------
APCo Senior Unsecured Notes $200 3.60 2008
APCo Senior Unsecured Notes 200 5.95 2033
APCo Installment Purchase
Contracts 100 5.50 2022
CSPCo Senior Unsecured Notes 250 5.50 2013
CSPCo Senior Unsecured Notes 250 6.60 2033
KPCo Senior Unsecured Notes 75 5.625 2032
OPCo Senior Unsecured Notes 250 5.50 2013
OPCo Senior Unsecured Notes 250 6.60 2033
SWEPCo Senior Unsecured Notes 100 5.375 2015
SWEPCo Secured Note 44 4.47 2011
TCC Senior Unsecured Notes 150 3.00 2005
TCC Senior Unsecured Notes 100 Variable 2005
TCC Senior Unsecured Notes 275 5.50 2013
TCC Senior Unsecured Notes 275 6.65 2033
TNC Senior Unsecured Notes 225 5.50 2013
Type Principal Interest Due
Company of Debt Amount Rate Date
------- ------- ----------- -------- ----
Retirements (in millions) (%)
-----------
APCo First Mortgage Bonds $ 70 8.50 2022
APCo First Mortgage Bonds 30 7.80 2023
APCo First Mortgage Bonds 20 7.15 2023
APCo Installment Purchase
Contracts 10 7.875 2013
APCo Installment Purchase
Contracts 40 6.85 2022
APCo Installment Purchase
Contracts 50 6.60 2022
APCo Senior Unsecured Notes 100 7.20 2038
APCo Senior Unsecured Notes 100 7.30 2038
CSPCo First Mortgage Bonds 2 8.70 2022
CSPCo First Mortgage Bonds 15 8.55 2022
CSPCo First Mortgage Bonds 14 8.40 2022
CSPCo First Mortgage Bonds 13 8.40 2022
CSPCo First Mortgage Bonds 13 6.80 2003
CSPCo First Mortgage Bonds 26 6.55 2004
CSPCo First Mortgage Bonds 26 6.75 2004
CSPCo First Mortgage Bonds 40 7.90 2023
CSPCo First Mortgage Bonds 33 7.75 2023
I&M First Mortgage Bonds 75 8.50 2022
I&M First Mortgage Bonds 15 7.35 2023
I&M Junior Debentures 40 8.00 2026
I&M Junior Debentures 125 7.60 2038
KPCo Junior Debentures 40 8.72 2025
OPCo First Mortgage Bonds 30 6.75 2003
PSO First Mortgage Bonds 35 6.25 2003
SWEPCo First Mortgage Bonds 55 6.625 2003
SWEPCo Secured Note 1 4.47 2011
TCC First Mortgage Bonds 18 7.50 2023
TCC First Mortgage Bonds 16 6.875 2003
TCC Securitization Bonds 32 3.54 2005
In addition to the transactions reported in the table above, the
following table lists intercompany retirements of debt due to AEP.
Type Principal Interest Due
Company of Debt Amount Rate Date
------- ------- ----------- -------- ----
Retirements (in millions) (%)
-----------
CSPCo Notes Payable $160 6.501 2006
KPCo Notes Payable 15 4.336 2003
OPCo Notes Payable 240 6.501 2006
OPCo Notes Payable 60 4.336 2003
In July 2003, OPCo issued the following Senior Unsecured Notes:
Principal Due
Amount Interest Rate Date
----------- ------------- ----
(in millions) (%)
$225 million 4.85% 2014
225 million 6.375% 2033
CONTROLS AND PROCEDURES
During the second quarter of 2003, AEP's management, including the principal
executive officer and principal financial officer, evaluated AEP's disclosure
controls and procedures related 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 June 30, 2003, these officers concluded that the disclosure controls and
procedures in place provide reasonable assurance that the disclosure controls
and procedures can accomplish 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 conditions
warrant.
There have not been any changes in AEP's internal controls over financial
reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the
Exchange Act) during the second quarter of 2003 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 8 to AEP's consolidated
financial statements and Note 7 to AEP's registrant subsidiaries' respective
financial statements, both entitled Commitments and Contingencies, incorporated
herein by reference.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo,
- --------------------------------------------------------------------------
I&M, and OPCo
-------------
As discussed in Note 9 of the Combined Notes to Financial Statements in the 2002
Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003),
AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding
generating plant emissions under the Clean Air Act. Federal EPA and a number of
states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities
modified certain units at coal-fired generating plants in violation of the
Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S.
District Court for the Southern District of Ohio. A separate lawsuit initiated
by certain special interest groups was consolidated with the Federal EPA case.
The alleged modification of the generating units occurred over a 20 year
period.
Under the Clean Air Act, 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
Clean Air Act 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 that claims for civil penalties are limited to the
five-year period prior to the filing date of the complaints. 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 similar case pending in the Southern District of Ohio against Ohio
Edison Company, an unrelated 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 March 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 June 24, 2003, the United States Court of Appeals for the 11th Circuit issued
an order invalidating the administrative compliance order issued by Federal EPA
to the Tennessee Valley Authority for similar alleged 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 Clean Air Act is unconstitutional.
On June 26, 2003, the United States Circuit 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 central
issue in these petitions concerns the lawfulness of the emissions increase test,
as currently interpreted and applied by Federal EPA in its utility enforcement
actions. A decision by the D. C. Circuit could significantly impact further
proceedings in the AEP case.
Management is unable to estimate the loss or range of loss related to the
contingent liability for civil penalties under the Clear Air Act proceedings and
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. In the event 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 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.
Item 4. Submission of Matters to a Vote of Security Holders.
---------------------------------------------------
AEP
The annual meeting of shareholders was held in Columbus, Ohio, on April
23, 2003. The holders of shares entitled to vote at the meeting or their proxies
cast votes at the meeting with respect to the following three matters, as
indicated below:
1. Election of thirteen directors to hold office until the next
annual meeting and until their successors are duly elected. Each
nominee for director received the votes of shareholders as
follows:
Number of Shares Number of
Nominee Voted For Votes Withheld
------- ---------------- --------------
E. R. Brooks 309,487,577 12,115,867
Donald M. Carlton 308,370,730 13,232,714
John P. DesBarres 309,518,825 12,084,619
E. Linn Draper, Jr. 312,545,954 9,057,490
Robert W. Fri 309,219,713 12,383,731
William R. Howell 309,136,662 12,466,782
Lester A. Hudson, Jr. 312,679,273 8,924,171
Leonard J. Kujawa 308,147,027 13,456,417
Richard L. Sandor 309,363,867 12,239,577
Thomas V. Shockley, III 312,652,348 8,951,096
Donald G. Smith 309,277,366 12,326,078
Linda Gillespie Stuntz 309,251,337 12,352,107
Kathryn D. Sullivan 308,205,408 13,398,036
2. Shareholder proposal submitted by First Investors Trust. The proposal
was disapproved by a vote of the shareholders as follows:
Votes FOR 39,599,579
Votes AGAINST 203,803,580
Votes ABSTAINED 6,390,989
Broker NON-VOTES* 71,809,331
3. Shareholder proposal submitted by Connecticut Retirement and
Trust Funds and Christian Brothers Investment Services, Inc. The
proposal was disapproved by a vote of the shareholders as
follows:
Votes FOR 58,589,132
Votes AGAINST 159,143,612
Votes ABSTAINED 32,068,627
Broker NON-VOTES* 71,802,108
*A non-vote occurs when a nominee holding shares for a beneficial
owner votes on one proposal, but does not vote on another
proposal because the nominee does not have discretionary
voting power and has not received instructions from the
beneficial owner.
APCo
The annual meeting of stockholders was held on April 22, 2003 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR
each of the following seven persons for election as directors and there were no
votes withheld and such persons were elected directors to hold office for one
year or until their successors are elected and qualify:
E. Linn Draper, Jr. Robert P. Powers
Henry W. Fayne Thomas V. Shockley, III
Thomas M. Hagan Susan Tomasky
Armando A. Pena
TCC
Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 10, 2003, the following seven persons were
elected directors to hold office for one year or until their successors are
elected and qualify:
E. Linn Draper, Jr. Robert P. Powers
Henry W. Fayne Thomas V. Shockley, III
Thomas M. Hagan Susan Tomasky
Armando A. Pena
I&M
Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 22, 2003, the following thirteen persons were
elected directors to hold office for one year or until their successors are
elected and qualify:
Karl G. Boyd Susanne M. Moorman
E. Linn Draper, Jr. Robert P. Powers
John E. Ehler John R. Sampson
Henry W. Fayne Thomas V. Shockley, III
Thomas M. Hagan David B. Synowiec
David L. Lahrman Susan Tomasky
Marc E. Lewis
OPCo
The annual meeting of shareholders was held on May 6, 2003 at 1
Riverside Plaza, Columbus, Ohio. At the meeting there were 27,952,473 votes cast
FOR:
Each of the following seven persons for election as directors and there
were no votes withheld and such persons were elected directors to hold
office for one year or until their successors are elected and qualify:
E. Linn Draper, Jr. Robert P. Powers
Henry W. Fayne Thomas V. Shockley, III
Thomas M. Hagan Susan Tomasky
Armando A. Pena
SWEPCo
Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 9, 2003, the following seven persons were
elected directors to hold office for one year or until their successors are
elected and qualify:
E. Linn Draper, Jr. Robert P. Powers
Henry W. Fayne Thomas V. Shockley, III
Thomas M. Hagan Susan Tomasky
Armando A. Pena
Item 5. Other Information.
-----------------
NONE
Item 6. Exhibits and Reports on Form 8-K.
--------------------------------
(a) Exhibits:
--------
AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
Exhibit 12 - Computation of Consolidated Ratio of Earnings to
Fixed Charges.
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
Exhibit 31.1 - Certification of Chief Executive Officer Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 31.2 - Certification of Chief Financial Officer Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.1 - Certification of Chief Executive Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the United States
Code.
Exhibit 32.2 - Certification of Chief Financial Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the United States
Code.
(b) Reports on Form 8-K:
AEGCo, APCo, I&M, KPCo, PSO, SWEPCo, TCC and TNC
The following reports on Form 8-K were filed during the quarter ended
June 30, 2003.
Company Reporting Date of Report Item Reported
----------------- -------------- -------------
AEP, APCo, CSPCo, May 14, 2003 Item 5. Other Events and
I&M, KPCo, OPCo, Regulation FD Disclosure
PSO, SWEPCo, TCC, TNC Item 7. Financial Statements
and Exhibits
APCo April 30, 2003 Item 5. Other Events and
Regulation FD Disclosure
Item 7. Financial Statements
And Exhibits
KPCo June 13, 2003 Item 5. Other Events and
Regulation FD Disclosure
Item 7. Financial Statements
And Exhibits
SWEPCo April 8, 2003 Item 5. Other Events and
Regulation FD Disclosure
Item 7. Financial Statements
And Exhibits
Signatures
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 signatures 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/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto
----------------------- ----------------------------
Geoffrey S. Chatas Joseph M. Buonaiuto
Treasurer 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/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto
----------------------- ----------------------------
Geoffrey S. Chatas Joseph M. Buonaiuto
Treasurer Controller and Chief Accounting Officer
Date: August 12, 2003