UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended MARCH 31, 2002
OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended SEPTEMBER 30, 2001
[ ] 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)
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
40 Franklin Road, Roanoke, Virginia 24011
Telephone (540) 985-2300
0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600
539 North Carancahua Street
Corpus Christi, Texas 78401-2802
Telephone (361) 881-5300
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
One Summit Square
P.O. Box 60, Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1701 Central Avenue, Ashland, Kentucky 41101
Telephone (800) 572-1141
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
301 Cleveland Avenue S.W., Canton, Ohio 44701
Telephone (330) 456-8173
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA 73-0410895
(An Oklahoma Corporation)
212 East 6th Street, Tulsa, Oklahoma 74119-1212
Telephone (918) 599-2000
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455
(A Delaware Corporation)
428 Travis Street, Shreveport, Louisiana 71156-0001
Telephone (318) 673-3000
0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation)
75-0646790 301 Cypress Street, Abilene, Texas 79601-58201 Riverside Plaza, Columbus, Ohio
43215-2373 Telephone (915) 674-7000(614) 223-1000
AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company,
Public Service Company of Oklahoma and West Texas Utilities Company 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.
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
-------- --------
The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at October 31, 2001April 30, 2002 was 322,235,005.322,822,489.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended September 30, 2001March 31, 2002
CONTENTS
Page
Glossary of Terms i - ii
Forward-Looking Information iii
Part I. FINANCIAL INFORMATION
Items 1 and 2 Financial Statements and Management's Discussion and
Analysis of Results of Operations:
American Electric Power Company, Inc. and Subsidiary Companies:
Management's Discussion and Analysis of Results of Operations A-1 - A-2A-6
Consolidated Financial Statements A-3A-7 - A-7A-11
AEP Generating Company:
Management's Narrative Analysis of Results of Operations B-1
Financial Statements B-2 - B-5
Appalachian Power Company, Inc. and Subsidiaries:
Management's Discussion and Analysis of Results of Operations C-1 - C-2C-4
Consolidated Financial Statements C-3C-5 - C-7C-9
Central Power and Light Company and Subsidiary:Subsidiaries:
Management's Discussion and Analysis of Results of Operations D-1 - D-2D-4
Consolidated Financial Statements D-3D-5 - D-6D-8
Columbus Southern Power Company and Subsidiaries:
Management's Narrative Analysis of Results of Operations E-1 - E-2E-5
Consolidated Financial Statements E-3E-6 - E-6E-9
Indiana Michigan Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations F-1 - F-2F-5
Consolidated Financial Statements F-3F-6 - F-7F-10
Kentucky Power Company
Management's Narrative Analysis of Results of Operations G-1 - G-2G-4
Financial Statements G-3G-5 - G-7G-9
Ohio Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations H-1 - H-2H-4
Consolidated Financial Statements H-3H-5 - H-7H-9
Public Service Company of Oklahoma and Subsidiaries:
Management's Narrative Analysis of Results of Operations I-1 - I-2I-4
Consolidated Financial Statements I-3I-5 - I-6I-8
Southwestern Electric Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations J-1 - J-2J-4
Consolidated Financial Statements J-3J-5 - J-6J-8
West Texas Utilities Company:
Management's Narrative Analysis of Results of Operations K-1 - K-2K-4
Financial Statements K-3K-5 - K-6
K-8
Footnotes to Financial Statements L-1 - L-14L-11
Item 2. Registrants' Combined Management Discussion and Analysis of
Financial Condition, Contingencies and Other Matters M-1 - M-7
Item 3. Quantitative and Qualitative Disclosures About Market Risk N-1 - N-2N-8
Part II. OTHER INFORMATION
Item 5. Other Information O-1
Item 6. Exhibits and Reports on Form 8-K O-1
(a) Exhibits
Exhibit 12
(b) Reports on Form 8-K
SIGNATURE P-1
This combined Form 10-Q is separately filed by American Electric Power
Company, Inc., AEP Generating Company, Appalachian Power Company, Central Power
and Light Company, Columbus Southern Power Company, Indiana Michigan Power
Company, Kentucky Power Company, Ohio Power Company, Public Service Company of
Oklahoma, Southwestern Electric Power Company and West Texas Utilities 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 subsidiaries consolidated.
AEP Credit, Inc.................... AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated and unaffiliated domestic electric utility companies.
AEP East electric operating
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 electric operating
companies.......................... CPL, PSO, SWEPCo and WTU.
Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
utilities.
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.
CLECO.............................. Central Louisiana Electric Company,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.
CPL................................ Central Power and Light Company, an AEP electric utility subsidiary.
CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW............................... Central and South West Corporation, a subsidiary of AEP.
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.
DHMV............................... Dolet Hills Mining Venture.
DOE................................ United States Department of Energy.
EBIT............................... Earnings Before Interest Charges and Income Taxes.
ECOM............................... Excess Cost Over Market.EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT.............................. The Electric Reliability Council of Texas.
FASB............................... Financial Accounting Standards Board.
Federal EPA........................ United States Environmental Protection Agency.
FERC............................... Federal Energy Regulatory Commission.
FMB................................ First Mortgage Bonds
GAAP............................... Generally Accepted Accounting Principles.
HPL................................ Houston Pipe Line Company.
I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary.
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.
LIBOR.............................. London InterBank Offered Rate.
LIG................................ Louisiana Intrastate Gas.
Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
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.
MTN................................ Medium Term Notes.
MW................................. Megawatt.
MWH................................ Megawatthour.
Nox................................NEIL............................... Nuclear Electric Insurance Limited.
NOx................................ Nitrogen oxide.
NoxNOx Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states
including seven of the states in which AEP companies operates.
NRC................................ Nuclear Regulatory Commission.
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:registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU.
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 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of
--------------------------------
Long-Lived Assets and for Long-Lived Assets to be Disposed of.
--------------------------------------------------------------
SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
-------------------------------------
and Hedging Activities.
----------------------SNF................................ Spent Nuclear Fuel.
SPP................................ Southwest Power Pool.
STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by CPL.Central Power and Light
Company, an AEP electric utility subsidiary .
SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary.
Texas Restructuring Legislation........................Legislation....
Legislation enacted in 1999 to restructure
the electric utility industry in Texas.
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.
WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary.
Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by CSPCo.Columbus
Southern Power Company, an AEP subsidiary.
FORWARD-LOOKING INFORMATION
This report made by AEP and certain of its subsidiaries contains
forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Although AEP and each of its 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
power generation business.
o The structure and timing of a competitive market and its impact on
energy prices or fixed rates.
o The ability to recover stranded costs in connection with
possible/proposed deregulation of generation.
o New legislation and government regulations.
o The ability of AEP to successfully control its costs.
o The success of new business ventures.
o International developments affecting AEP's foreign investments.
o The economic climate and growth in AEP's service territory.
o Inflationary trends.
o Electricity and gas market prices.
o Interest rates
o Other risks and unforeseen events.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000American Electric Power Company, Inc.'s (AEP) principal operating
business segments and their major activities are:
o Wholesale
o Generation of electricity for sale to retail and
wholesale customers
o Gas pipeline and storage services
o Marketing and trading of electricity, gas and coal
o Coal mining, bulk commodity barging operations and other
energy supply related business.
o Energy Delivery
o Domestic electricity transmission,
o Domestic electricity distribution
o Other Investments
o Foreign electric distribution and supply investments,
o Telecommunication services.
Net Income
First quarter 2002 net income increased by $62of $181 million or 20 cents$0.56 per share for the
quarter and by $430was
down 32% from last year's earnings of $266 million or $1.33$0.83 per share year-to-date. The results forshare.
Unfavorable market conditions and the quartereffect of a March 2001 gain on the sale of
the Frontera power plant caused the earnings decline.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As the owner of cost-based rate-regulated electric
public utility companies, AEP Co., Inc.'s consolidated financial statements
reflect a favorable variance from an extraordinary loss from
deregulation recordedthe actions of regulators that can result in the third quarterrecognition of 2000revenues
and an accounting change dueexpenses in different time periods than enterprises that are not rate
regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and
regulatory liabilities (future revenue reductions or refunds) are recorded to
new accounting rules recordedreflect the economic effects of regulation by matching expenses with their
recovery through regulated revenues in the third quartersame accounting period.
When regulatory assets are probable of 2001. Income before
extraordinary itemsrecovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and cumulative effectDelivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Domestic Gas Pipeline and Storage Activities - We recognize revenues from
domestic gas pipeline and storage services when gas is delivered to contractual
meter points or when services are provided. Transportation and storage revenues
also include the accrual of the accounting change was unchanged
for the quarter. In the year-to-date period income before extraordinary itemsearned, but unbilled and/or not yet metered gas.
Energy Marketing and the cumulative effect of the accounting change increased by $425 million or
$1.31 per share. The impact on comparative net income from the extraordinary
itemsTrading Activities - We engage in non-regulated wholesale
electricity and the cumulative effect of the accounting change was $5 million
favorable for the year-to-date period.
Our wholesale business continued to perform well despite a slowing
economy that reduced both wholesale energy margins and energy use by industrial
customers. Our wholesale business, which includes generation, retail sales of
power and wholesale power andnatural gas marketing and trading transactions (trading
activities). Trading activities involve the purchase and sale of energy under
forward contracts at fixed and variable prices and the buying and selling of
financial energy contracts which include exchange futures and options and
over-the-counter options and swaps. Although trading contracts are generally
short-term, there are also long-term trading contracts. We recognize revenues
from trading activities generally based on changes in the fair value of open
energy trading contracts.
Recording the net change in the fair value of open trading contracts as
revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. Under MTM accounting the change in the unrealized gain or loss
throughout a contract's term is recognized in each accounting period. When the
contract actually settles, that is, the energy is actually delivered in a sale
or received in a purchase or the parties agree to forego delivery and receipt
and net settle in cash, the unrealized gain or loss is reversed out of revenues
and the actual realized cash gain or loss is recognized in revenues for a sale
or in purchased energy expense for a purchase. Therefore, over the term of a
trading contract an unrealized gain or loss is recognized as the contract's
market value changes. When the contract settles the total gain or loss is
realized in cash but only the difference between the accumulated unrealized net
gains or losses recorded in prior months and the cash proceeds is recognized.
Unrealized mark-to-market gains and losses are included in the Balance Sheet as
energy trading and derivative contract assets or liabilities.
The majority of our trading activities represent physical forward
electricity and gas pipelinecontracts that are typically settled by entering into
offsetting contracts. An example of our trading activities is when, in January,
we enter into a forward sales contract to deliver electricity or gas in July. At
the end of each month until the contract settles in July, we would record any
difference between the contract price and storages services, continuedthe market price as an unrealized gain
or loss in revenues. In July when the contract settles, we would realize a gain
or loss in cash and reverse to revenues the previously recorded cumulative
unrealized gain or loss. Prior to settlement, the change in the fair value of
physical forward sale and purchase contracts is included in revenues on a net
basis. Upon settlement of a forward trading contract, the amount realized is
included in revenues for a sales contract and the realized cost is included in
purchased energy expense for a purchase contract with the prior change in
unrealized fair value reversed in revenues.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity or gas in July. If we do nothing else with these contracts
until settlement in July and if the commodity type, volumes, delivery point,
schedule and other key terms match then the difference between the sale price
and the purchase price represents a fixed value to be realized when the
contracts settle in July. If the purchase contract is perfectly matched with the
sales contract, we have effectively fixed the profit or loss; specifically it is
the difference between the contracted settlement price of the two contracts.
Mark-to-market accounting for these contracts from this point forward will have
no further impact on operating results but has an offsetting and equal effect on
trading contract assets and liabilities. Of course we could have also done a
similar transaction but enter into a purchase contract prior to entering into a
sales contract. If the sale and purchase contracts do not match exactly as to
commodity type, volumes, delivery point, schedule and other key terms, then
there could be continuing mark-to-market effects on revenues from recording
additional changes in fair values using mark-to-market accounting.
Trading of electricity and gas options, futures and swaps, represents
financial transactions with unrealized gains and losses from changes in fair
values reported net in revenues until the contracts settle. When these contracts
settle, we record the net proceeds in revenues and reverse to revenues the prior
cumulative unrealized net gain or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on Company-developed valuation models. These models
estimate future energy prices based on existing market and broker quotes and
supply and demand market data and assumptions. The fair values determined are
reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is
the risk that the counterparty to the contract will fail to perform or fail to
pay amounts due AEP. Liquidity risk represents the risk that imperfections in
the market will cause the price to be less than or more than what the price
should be based purely on supply and demand. There are inherent risks related to
the underlying assumptions in models used to fair value open long-term trading
contracts. We have independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant contributor to our earnings
despite loweradverse or favorable
effects on future results of operations and cash flows if market prices at
settlement do not correlate with the Company-developed price models. This is
particularly true for long-term contracts.
We also mark-to-market derivatives that are not trading contracts in
accordance with generally accepted accounting principles. Derivatives are
contracts whose value is derived from the market value of an underlying
commodity.
As stated above, AEP records and reduced volatility. Although our power marketingreports upon settlement sales under
forward trading contracts as revenues and purchases under forward trading
operations had an adverse effectcontracts as purchased energy expense. If settled forward sale and purchase
contracts were reported on a net basis, the third quarter, our gas
marketingamounts of revenues and trading more than offset the decline in power trading. For the
year-to-date period, earnings from both power and gas marketing and trading
improved.
Income statement line items which changed significantly were:purchased
energy expense reported would have been:
Increase (Decrease)
Third Quarter Year-to-DateThree Months Ended March 31,
2002 2001
(in millions)
% (in millions) %
------------- - ------------- -Gross Net Gross Net
----- --- ----- ---
Revenues $6,777 58 $21,216 82Revenues:
Electricity Marketing and Trading $ 8,524 $1,999 $ 9,272 $2,103
Gas Marketing and Trading 3,591 382 3,606 262
Domestic Electricity Delivery 798 798 789 789
Other Investments 501 501 568 568
------- ------ ------- ------
Total $13,414 $3,680 $14,235 $3,722
======= ====== ======= ======
Gross Net Gross Net
----- --- ----- ---
Fuel and Purchased Power Expense 6,806 74 20,610 104
MaintenanceEnergy Expense:
Electricity Marketing and Trading $ 7,289 $ 764 $ 8,221 $1,052
Gas Marketing and Trading 3,673 464 3,538 194
Other Operation Expense (43) (4) 148 5
Writeoff of Merger-Related Costs (16) (80) (165) (91)
Other Income, net (7) (30) 83 141
Interest and Preferred Dividends (22) (8) (34) (4)
Income Taxes 4 2 218 63
Extraordinary Items 44 N.M. (13) (37)
Cumulative Effect 18 N.M. 18 N.M.
N.M. = Not MeaningfulInvestments 345 345 343 343
------- ------ ------- ------
Total $11,307 $1,573 $12,102 $1,589
======= ====== ======= ======
The increasesWe defer as regulatory assets or liabilities the effect on net income
of marking to market open forward electricity trading contracts in revenues wereour regulated
jurisdictions since these transactions are included in cost of service on a
settlement basis for ratemaking purposes. Changes in mark-to-market valuations
impact net income in our non-regulated gas and electricity business.
Volatility in energy commodities markets affects the fair values of all
of our open trading and derivative contracts exposing AEP to market risk and
causing our results of operations to be subject to volatility. See "Quantitative
and Qualitative Disclosures Market Risks" section of this report for a
discussion of the policies and procedures AEP uses to manage its exposure to
market and other risks from trading activities.
RESULTS OF OPERATIONS
Net income for the first quarter of 2002 decreased by $85 million from
last year's results due to substantial increasesthe effects of the sale of Frontera power plant in
the first quarter of 2001 and strong performance last year from the wholesale
business reflecting market conditions that were more favorable than in 2002.
Lower energy demand in the first quarter of 2002 depressed margins from
wholesale electric and gas trading volumes. Wholesale natural gas trading volume for the quarter
was 1,337 billion cubic feet, a 265 percent increase from third-quarter 2000
volume of 366 billion cubic feet. Electric trading volume for the quarter
increased 66 percent to 148 million MWH.
The increase in gas trading volume is from:
o continued expansion of our trading team
o HPL acquisition on June 1, 2001
o expansion into new markets
The increase in electric trading volume is primarily from:
o continued expansion of our trading team
o increased liquidity in markets
While tradingmarketing and marketing volumes rose, sales to industrial customers
decreased and, in the third quarter, sales to wholesale customers also declined.
We also experienced lower wholesale prices. The slowing economy has reduced
demand and wholesale prices.
Our fuel and purchased power expense increased due to increased trading
volume, particularly gas, and an increase in nuclear generation. Cook Plant's
two nuclear generating units were out of service in 2000 through June 2000 and
December 2000.
Maintenance and other operation expense declined in the third quarter
due to the return to service of the Cook Nuclear units in 2000. Partially
offsetting this decrease were accruals for severance related to corporate
restructuring.trading. In the year-to-date period, additional traders' incentive
compensation, costs associated with the construction of gas-fired plants for
non-affiliates and the accruals for severance costs caused maintenance and other
operation expense to rise. The increase was offset, in part, by not incurring
restart costs for the Cook Plant. Revenues from project fees more than offset
the charges for third party construction.
The write-off of deferred merger costs in 2000 included transaction and
transition costs not recoverable from ratepayers under regulatory commission
approved settlement agreements.
The completion in March 2001 ofwe completed the
sale of Frontera, one of the generating plants required to be divested under the
FERC - approved merger settlement agreements, producedagreements. The sale resulted in a $73$46 million
gain recordedafter tax gain.
Increase (Decrease)
(in millions) %
-
Revenues:
Electric Marketing and Trading $(748) (8)
Gas Marketing and Trading (15) -
Domestic Electricity Delivery 9 1
Other Investments (67) (12)
---
$(821) (6)
=====
The decline in other income for
the year-to-date period.
Lower average outstanding short-term debt balances andrevenues is mainly due to a decrease in average short-term interest rates accountedelectric
marketing and trading revenues. The decrease was driven largely by a decline in
demand due to mild weather and the slow recovery from the economic recession.
Heating degree days for the first quarter of 2002 were down 13.2 % from the same
quarter last year. Electricity sales to industrial customers decreased 7.1% from
the same period last year. The increase in gas trading volume can be attributed
to the acquisition of Houston Pipe Line (HPL) and expansion of our gas trading
operations around the pipeline. Revenues from other investments declined due to
a decrease in SEEBOARD revenues resulting from regulator imposed price
reductions.
Increase (Decrease)
(in millions) %
-
Fuel and Purchased Energy Expense:
Electric Marketing and Trading $(932) (11)
Gas Marketing and Trading 135 4
Other Investments 2 1
-
Total Fuel and Purchased Energy Expense (795) (7)
Maintenance and Other Operation Expense 84 9
Depreciation and Amortization Expense 23 7
Taxes Other Than Income Taxes 18 11
--
Total Operating Expenses $(670) (5)
=====
The decrease in fuel and purchased energy expense was primarily
attributable to a reduction in interestpower generation and preferred dividends.
Anpurchases and lower fuel
costs reflecting lower market prices than in the first quarter of 2001. Net
generation decreased 5% from last year due to the reduced demand for electricity
and planned maintenance outages for various plants. The cost of purchased power
for resale was also lower due to reduced demand, a continuation of the market
conditions that developed in the fourth quarter of 2001. The increase in gas
marketing and trading purchased energy expense was primarily due to the
acquisition of HPL and expansion of gas trading activity around the pipeline.
Maintenance and other operation expense increased largely as a result of
material and labor costs incurred in connection with the construction of
gas-fired plants for third parties plus the expenses of MEMCO, a barging line;
Quaker Coal; and two power plants in the UK, all recently acquired businesses.
These cost increases were partially offset by a reduction in trading incentive
compensation. Project fees for the construction of gas-fired plants for third
parties are recognized in revenues on a percentage of completion method,
consequently, the charges to expense for material and labor costs do not
adversely affect net income.
Other income decreased due to the gain from the sale of Frontera in
2001.
Other expenses increased due to a write off of goodwill on Gas Power
Systems resulting from management's decision to exit the business (See Note 2).
The decrease in income taxes is predominately due to a decrease in
pre-tax income causedand changes in certain book/tax timing differences accounted for
on a flow-through basis.
The decrease in interest was primarily due to a decrease in the
increase in income taxes.
Inoutstanding balance of long-term debt since the secondfirst quarter of 2001, we recorded an extraordinary lossthe
refinancing of $48
million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio
deregulation (see Note 2). The application of regulatory accounting for
generation was discontinueddebt at favorable interest rates and a reduction in 2000 which resulted in after tax extraordinary
items of:
o a $9 million gain in June of 2000 for the Virginia and West Virginia
jurisdictions and
o $44 million loss in September of 2000 for the Ohio jurisdiction
New accounting rules that became effective July 1, 2001 required us to
mark to market certain fuel supply contracts that qualify as financial
derivatives. The effect of initially adopting the new rules at July 1, 2001 was
$18 million, net of tax, which is reported as a cumulative effect of accounting
change on the income statement.short-term
interest rates.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,March 31,
2002 2001 2000 2001 2000
---- ----
---- ----
REVENUES:
Electricity Marketing and Trading $ 8,524 $ 9,272
Gas Marketing and Trading 3,591 3,606
Domestic Electricity Delivery 798 789
Other Investments 501 568
------- -------
TOTAL REVENUES $18,385 $11,608 $47,078 $25,862
------- -------13,414 14,235
------- -------
EXPENSES:
Fuel and Purchased Power 16,008 9,202 40,477 19,867Energy:
Electricity Marketing and Trading 7,289 8,221
Gas Marketing and Trading 3,673 3,538
Other Investments 345 343
------- -------
TOTAL FUEL AND PURCHASED ENERGY 11,307 12,102
Maintenance and Other Operation 971 1,014 2,883 2,735
Non-recoverable Merger Costs 4 20 16 1811,042 958
Depreciation and Amortization 340 322 1,030 947359 336
Taxes Other Than Income Taxes 200 177 537 523
--- --- --- ---186 168
------- -------
TOTAL OPERATING EXPENSES 17,523 10,735 44,943 24,253
------ ------ ------ ------12,894 13,564
------- -------
OPERATING INCOME 862 873 2,135 1,609520 671
OTHER INCOME net 16 23 142 59
-- -- --- --
INCOME BEFORE17 53
OTHER EXPENSES 22 19
LESS: INTEREST 228 266
PREFERRED DIVIDENDS AND INCOME TAXES 878 896 2,277 1,668STOCK DIVIDEND REQUIREMENTS OF
SUBSIDIARIES 2 3
MINORITY INTEREST AND PREFERRED DIVIDENDS 252 274 762 796
--- --- --- ---IN FINANCE SUBSIDIARY 9 -
------- -------
239 269
INCOME BEFORE INCOME TAXES 626 622 1,515 872276 436
INCOME TAXES 223 219 566 348
--- --- --- ---
INCOME BEFORE EXTRAORDINARY ITEM
AND CUMULATIVE EFFECT 403 403 949 524
EXTRAORDINARY LOSS - EFFECTS
OF DEREGULATION - net of tax (See note 2) - (44) (48) (35)
CUMULATIVE EFFECT OF ACCOUNTING CHANGE - net of tax
(See note 2) 18 - 18 -
-- ------ -- ------95 170
------- -------
NET INCOME $ 421181 $ 359 $ 919 $ 489
======= ======266
======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 322 322
322 322
=== === === ===
EARNINGS PER SHARE:
Income Before Extraordinary Item and
Cumulative Effect $1.25 $ 1.25 $ 2.94 $ 1.63
Extraordinary Loss - (0.14) (0.15) (0.11)
Cumulative Effect .06 - .06 -
--- ----- --- -----
Earnings Per ShareSHARE (Basic and Dilutive) $1.31 $ 1.11 $ 2.85 $ 1.52: $0.56 $0.83
===== ====== ====== ===========
CASH DIVIDENDS PAID PER SHARE $0.60 $0.60 $1.80 $1.80
===== =====
===== =====
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(in millions)
ASSETS
- ------
CURRENT ASSETS:
Cash and Cash Equivalents $ 379306 $ 437333
Accounts Receivable (net) 2,824 3,6992,554 1,882
Fuel, Materials and Supplies 963 1,066
Energy Trading and Derivative Contracts 13,114 16,6279,327 8,572
Other 1,690 1,268
----- -----1,130 710
------- -------
TOTAL CURRENT ASSETS 18,007 22,031
------ ------14,280 12,563
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 16,533 16,32817,483 17,477
Transmission 5,824 5,6095,937 5,879
Distribution 11,169 10,84311,431 11,310
Other (including gas, and coal mining assets and
nuclear fuel) 4,538 4,0774,838 4,941
Construction Work in Progress 949 1,231
--- -----1,179 1,102
------- -------
Total Property, Plant and Equipment 39,013 38,08840,868 40,709
Accumulated Depreciation and Amortization 15,941 15,695
------ ------16,421 16,166
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 23,072 22,393
------ ------24,447 24,543
------- -------
REGULATORY ASSETS 3,542 3,698
----- -----2,573 3,162
------- -------
SECURITIZED TRANSITION ASSET 758 -
------- -------
INVESTMENTS IN POWER, DISTRIBUTION AND
COMMUNICATIONS PROJECTS 563 782
--- ---599 677
------- -------
GOODWILL (net of amortization) 1,360 1,382
----- -----1,591 1,546
------- -------
INTANGIBLE ASSETS 471 441
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 3,375 1,620
----- -----3,268 2,370
------- -------
OTHER ASSETS 2,900 2,642
----- -----2,166 1,979
------- -------
TOTAL $52,819 $54,548$50,153 $47,281
======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 1,8472,162 $ 2,6272,245
Short-term Debt 3,575 4,3333,984 4,025
Long-term Debt Due Within One Year 1,550 1,1521,231 1,430
Energy Trading And Derivative Contracts 12,542 16,8019,231 8,311
Other 2,461 2,154
----- -----2,519 2,088
------- -------
TOTAL CURRENT LIABILITIES 21,975 27,067
------ ------19,127 18,099
------- -------
LONG-TERM DEBT 9,925 9,602
----- -----10,571 9,753
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 3,229 1,381
----- -----3,066 2,183
------- -------
DEFERRED INCOME TAXES 4,930 4,875
----- -----4,765 4,823
------- -------
DEFERRED INVESTMENT TAX CREDITS 502 528
--- ---482 491
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 1,019 617
----- ---1,175 948
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 197 203
--- ---192 194
------- -------
OTHER NONCURRENT LIABILITIES 1,413 1,706
----- -----1,362 1,334
------- -------
COMMITMENTS AND CONTINGENCIES (Note 8)
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
SUBSIDIARIES 321 334
--- ---321
------- -------
MINORITY INTEREST IN SUBSIDIARIES 773 20
--- --FINANCE SUBSIDIARY 750 750
------- -------
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 156 161
--- ---156
------- -------
COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
2002 2001 2000
---- ----
Shares Authorized. . . .Authorized.. . 600,000,000 600,000,000
Shares Issued. . . . . . . 331,202,497 331,019,146.331,618,850 331,234,997
(8,999,992 shares were held in treasury at
September 30, 2001March 31, 2002 and December 31, 2000)2001) 2,156 2,153 2,152
Paid-in Capital 2,916 2,9152,912 2,906
Accumulated Other Comprehensive Income (Loss) (128) (103)(170) (126)
Retained Earnings 3,438 3,090
----- -----3,288 3,296
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 8,379 8,054
----- -----8,186 8,229
------- -------
TOTAL $52,819 $54,548$50,153 $47,281
======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in millions)
OPERATING ACTIVITIES:
Net Income $ 919181 $ 489266
Adjustments for Noncash Items:
Depreciation and Amortization 1,054 976362 352
Deferred Federal Income Taxes 131 40(63) 68
Deferred Investment Tax Credits (26) (26)
Amortization(9) (9)
Net Mark to Market Adjustment of Deferred Property Taxes 142 138
Amortization of Cook Plant Restart Costs 30 30
Deferred Costs Under Fuel Clause Mechanisms 240 (276)
Miscellaneous Accrued Expenses (238) 191
Extraordinary Loss - Discontinuance of SFAS 71 48 35
Cumulative Effect of Accounting Change (18) -Energy Trading Contracts 219 (57)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 921 (927)(832) 615
Fuel, Materials and Supplies (114) 88100 (13)
Accrued Utility Revenues (4) (134)(55) 39
Prepayments and Other (83) (280)(58) (68)
Accounts Payable (1,108) 44520 (499)
Taxes Accrued 163 (3)
Revenue Refunds8 15
Interest Accrued 106 65
Rent Accrued - Rockport Plant Unit 2 (15)
Energy Trading Contracts (net) (653) (23)37 37
Option Premiums 52 156
Change in Other (net) (209) (220)
---- ----Assets (339) (378)
Change in Other Liabilities 257 (5)
----- -----
Net Cash Flows From Operating Activities 1,197 528(14) 584
----- --------
INVESTING ACTIVITIES:
Construction Expenditures (1,303) (1,204)
Purchase of Houston Pipe Line (727) -
Sale of Yorkshire 383 -
Sale of Frontera 265 -(353) (315)
Other (54) (29)
--- ---(25) 109
----- -----
Net Cash Flows Used For Investing Activities (1,436) (1,233)
------ ------(378) (206)
----- -----
FINANCING ACTIVITIES:
Issuance of Common Stock 9 12
Issuance of Minority Interest 750 -14 3
Issuance of Long-term Debt 1,766 948914 132
Change in Short-term Debt (net) (717) 1,406
Retirement of Cumulative Preferred Stock (5) (20)(41) (266)
Retirement of Long-term Debt (1,033) (1,400)(313) (209)
Dividends Paid on Common Stock (580) (612)
---- ----(193) (193)
----- -----
Net Cash Flows FromUsed For Financing Activities 190 334
--- ---381 (533)
----- -----
Effect of Exchange Rate Change on Cash (9) 7
-- -(16) (7)
----- -----
Net Decrease in Cash and Cash Equivalents (58) (364)(27) (162)
Cash and Cash Equivalents at Beginning of Period 333 437
659
--- -------- -----
Cash and Cash Equivalents at End of Period $ 379306 $ 295
======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $469 million and $685
million and for income taxes was $208 million and $242275
===== =====
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $126 million and $115
million and for income taxes was $94 million and $178 million in 2002 and 2001,
respectively. Noncash acquisitions under capital leases were none in 2002 and
$19 million in 2001, and 2000,
respectively. Noncash acquisitions under capital leases were $39 million and $79
million in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated
Other
Common Paid-in Retained Accumulated Other Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- --------------------------- -----
(in millions)
JANUARY 1, 2000 $2,149 $2,898 $3,630 $ (4) $8,673
Issuance of Common Stock 2 10 12
Common Stock Dividends (612) (612)
Other 7 (1) 6
-
8,079
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Currency Translation Adjustment (171) (171)
Unrealized Loss on Securities 20 20
Net Income 489 489
---
Total Comprehensive Income 338
---------- ---------- ----------- -------- ---
SEPTEMBER 30, 2000 $2,151 $2,915 $3,506 $(155) $8,417
====== ====== ======= ===== ======
JANUARY 1, 2001 $2,152 $2,915 $3,090 $(103) $8,054
Issuance of Common Stock 1 8 94 4
Common Stock Dividends (580) (580)(193) (193)
Other (7) 9 2
-
7,485(5) (5)
------
7,860
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes
Currency Translation Adjustment (21) (21)(82) (82)
Unrealized Gain on Hedged Derivatives 2 2
Minimum Pension Liability (6) (6)Securities 13 13
Net Income 919 919
---266 266
------
Total Comprehensive Income 894
---------- ---------- ----------- --------- --------
SEPTEMBER 30,197
------ ------ ------ ----- ------
MARCH 31, 2001 $2,152 $2,914 $3,163 $(172) $8,057
====== ====== ====== ===== ======
JANUARY 1, 2002 $2,153 $2,916 $3,438 $(128) $8,379$2,906 $3,296 $(126) $8,229
Issuance of Common Stock 3 3
Common Stock Dividends (193) (193)
Other 6 4 10
------
8,049
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes
Currency Translation Adjustment (6) (6)
Unrealized Loss on Cash Flow
Hedges (38) (38)
Net Income 181 181
------
Total Comprehensive Income 137
------ ------ ------ ----- ------
MARCH 31, 2002 $2,156 $2,912 $3,288 $(170) $8,186
====== ====== ====== ===== ======
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 20012002 vs. THIRDFIRST QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
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 and a return on other
capital.
The increase incapital net of temporary cash investments.
Net income of $0.1 million or 4%declined $87,000 for the quarter
resulted primarily from an increase in capital on which a return is earned. Net
income for the year-to-date period was virtually unchanged.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $1.8 3 $0.7 N.M.
Fuel Expense 2.8 11 0.3 N.M.
Other Operation Expense 0.7 37 1.0 14
Maintenance Expense (0.6) (31) (0.4) (5)
Taxes Other Than Federal Income Taxes (0.5) (43) 1.0 30
Interest Charges (0.6) (52) (1.0) (34)
N.M. = Not Meaningful
The increasefirst quarter.
A decrease in operating revenues of $10,632,000 resulted primarily from an increasea decrease
in recoverable expenses, especiallyprimarily fuel, and other operation expense. Recoverableas generation declined due to a
decrease in the Rockport Plant's availability. Outages for planned maintenance
at both units in 2002 decreased the Rockport Plant's generation by 32%.
Operating expenses rosedeclined 18% as follows:
Increase (Decrease)
-------------------
(in thousands) %
-------------- -
Fuel $(10,145) (37)
Rent - Rockport Plant
generation increased in 2001 compared with last
year when the plant underwent scheduled maintenance outages in the third quarter
of 2000.Unit 2 - -
Other Operation 264 9
Maintenance 1,050 55
Depreciation 47 1
Taxes Other Than Income
Taxes 10 1
Income Taxes (1,818) (74)
--------
Total $(10,592) (18)
========
Fuel expense increaseddecreased due to an increasethe decline in generation reflecting the
length of outages in the third quarter 2000.generation.
The increase in other operation expense resulted from increasedis primarily due to higher
costs for employee benefits insurance and regulatory commission costs.property insurance.
Maintenance expense declined due to more extensive outages during
the third quarter 2000 for boiler maintenance and repair.
The decline in taxes other than federal income taxes for the quarter
resulted from a decrease in an accrual for state taxes as a result of a revised
taxable income estimate. Taxes other than federal income taxes for the
year-to-date period increased due to the accrualplanned outages in 2002.
The decrease in income taxes attributable to operations is primarily
due to an over-accrual of state income taxes based on an estimate of higher
taxable income for 2001.
Reductionsthe year 2001 than actually occurred. The over-accrual was
adjusted later in variable interest rates, reflecting market conditions, and
lower average short-term borrowing balances outstanding produced the decrease in
interest charges.2001.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,March 31,
2002 2001 2000 2001 2000
---- ----
---- ----
(in thousands)
OPERATING REVENUES $57,417 $55,658 $170,141 $169,452- Sales to AEP Affiliates $49,875 $60,507
------- ------- -------- --------
OPERATING EXPENSES:
Fuel 28,143 25,308 76,049 75,79117,500 27,645
Rent - Rockport Plant Unit 2 17,071 17,071
51,212 51,212
Other Operation 2,529 1,840 7,855 6,8943,222 2,958
Maintenance 1,415 2,042 7,312 7,7232,976 1,926
Depreciation 5,613 5,558 16,801 16,6045,633 5,586
Taxes Other Than Federal Income Taxes 662 1,164 4,431 3,414
Federal1,053 1,043
Income Taxes 369 466 1,177 1,464
--- --- ----- -----653 2,471
------- -------
TOTAL OPERATING EXPENSES 55,802 53,449 164,837 163,102
------ ------48,108 58,700
------- -------
OPERATING INCOME 1,615 2,209 5,304 6,3501,767 1,807
NONOPERATING INCOME 965 869 2,714 2,638
--- --- ----- -----2 -
NONOPERATING EXPENSES 12 9
NONOPERATING INCOME BEFORETAX CREDITS 832 871
INTEREST CHARGES 2,580 3,078 8,018 8,988
INTEREST CHARGES 529 1,106 1,924 2,918
--- ----- ----- -----696 689
------- -------
NET INCOME $ 2,0511,893 $ 1,972 $ 6,094 $ 6,0701,980
======= ======= ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,March 31,
2002 2001 2000 2001 2000
---- ----
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $11,847 $5,836$13,761 $ 9,722
$3,673
NET INCOME 2,051 1,972 6,094 6,0701,893 1,980
CASH DIVIDENDS DECLARED 1,050 959
- 2,877 1,935
--- ------ ----- ------------ -------
BALANCE AT END OF PERIOD $12,939 $7,808 $12,939 $7,808$14,604 $10,743
======= ====== ======= ======
The common stock of AEGCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $637,433 $635,215$639,544 $638,297
General 2,943 2,7953,012 3,012
Construction Work in Progress 3,979 4,292
----- -----9,649 6,945
-------- --------
Total Electric Utility Plant 644,355 642,302652,205 648,254
Accumulated Depreciation 331,268 315,566
------- -------342,515 337,151
-------- --------
NET ELECTRIC UTILITY PLANT 313,087 326,736
------- -------309,690 311,103
-------- --------
OTHER PROPERTY AND INVESTMENTS 119 6
--- -119
-------- --------
CURRENT ASSETS:
Cash and Cash Equivalents 188 2,757
Advances to Affiliates 3,478 -4,212 983
Accounts Receivable:
Affiliated Companies 18,823 21,37421,007 22,344
Miscellaneous 150 2,341147 147
Fuel - at average cost 15,487 11,00616,555 15,243
Materials and Supplies - at average cost 4,093 3,9794,382 4,480
Prepayments 396 145
--- ---128 244
-------- --------
TOTAL CURRENT ASSETS 42,615 41,602
------ ------46,431 43,441
-------- --------
REGULATORY ASSETS 5,267 5,504
----- -----5,149 5,207
-------- --------
DEFERRED CHARGES 3,340 754
----- ---3,816 1,471
-------- --------
TOTAL ASSETS $364,428 $374,602$365,205 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares $ 1,000 $ 1,000
Paid-in Capital 23,434 23,434
Retained Earnings 12,939 9,722
------ -----14,604 13,761
-------- --------
Total Common Shareowner'sShareholder's Equity 37,373 34,15639,038 38,195
Long-term Debt 44,791 -
------ -44,795 44,793
-------- --------
TOTAL CAPITALIZATION 82,164 34,156
------ ------83,833 82,988
-------- --------
OTHER NONCURRENT LIABILITIES 135 358
--- ---74 76
-------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 44,808
Advances from Affiliates - 28,06816,538 32,049
Accounts Payable:
General 9,033 6,1094,241 7,582
Affiliated Companies 6,785 7,7243,774 1,654
Taxes Accrued 12,194 4,99310,306 4,777
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Other 2,806 4,443
----- -----2,938 3,481
-------- --------
TOTAL CURRENT LIABILITIES 54,245 101,108
------ -------61,224 54,506
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
PLANT UNIT 2 118,010 122,188
------- -------115,225 116,617
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credit 57,209 59,71855,469 56,304
Amounts Due to Customers for Income Taxes 21,994 23,996
------ ------22,059 22,725
-------- --------
TOTAL REGULATORY LIABILITIES 79,203 83,714
------ ------77,528 79,029
-------- --------
DEFERRED INCOME TAXES 30,521 32,928
------ ------27,171 27,975
-------- --------
DEFERRED CREDITS 150 150
--- ----------- --------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $364,428 $374,602$365,205 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 6,0941,893 $ 6,070
Adjustments1,980
Adjustment for Noncash Items:
Depreciation 16,801 16,6045,633 5,586
Deferred Federal Income Taxes (4,409) (4,225)(1,470) (1,462)
Deferred Investment Tax Credits (2,509) (2,511)(835) (837)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (4,178) (4,178)(1,392) (1,392)
Deferred Property Taxes (922) (807)(2,693) (2,737)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable 4,742 (15,521)1,337 500
Fuel, Materials and Supplies (4,595) (731)(1,214) 661
Accounts Payable 1,985 (15,631)(1,221) 3,783
Taxes Accrued 7,201 4,6225,529 6,131
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other (net) (3,700) 1,056
------ -----Assets 586 199
Change in Other Liabilities (545) 375
-------- --------
Net Cash Flow From Operating Activities 34,974 3,212
------ -----24,072 31,251
-------- --------
INVESTING ACTIVITIES - Construction Expenditures (3,120) (3,413)
------ ------(4,282) (432)
-------- --------
FINANCING ACTIVITIES:
Return of Capital to Parent Company - (4,866)
Change in Short-term Debt (net) - (24,700)
Change in Advances from Affiliates (net) (31,546) 31,574(15,511) (27,849)
Dividends Paid (2,877) (1,935)
------ ------(1,050) (959)
-------- --------
Net Cash Flows From (Used For)Used For Financing Activities (34,423) 73
------- --(16,561) (28,808)
-------- --------
Net DecreaseIncrease in Cash and Cash Equivalents (2,569) (128)3,229 2,011
Cash and Cash Equivalents at Beginning of Period 983 2,757
317
----- ----------- --------
Cash and Cash Equivalents at End of Period $ 1884,212 $ 1894,768
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,489,000$1,108,000 and $2,671,000$644,000
and for income taxes was $1,352,000$176,000 and $3,101, 000$1,349,000 in 20012002 and 2000,2001, respectively.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists ofAPCo is a public utility engaged in the generation, regulated retail power sales and wholesale power marketing and trading; and
energy delivery which consists ofpurchase, sale,
transmission and distribution services. We
belongof electric power to 917,000 retail customers in
southwestern Virginia and southern West Virginia. APCo as a member of the AEP
Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale
sales to neighboring utility systems and power marketers including power trading
transactions. APCo also sells wholesale power to municipalities.
The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool members based on their relative peak demands and generating
reserves through the payment of capacity charges and the receipt of capacity
credits. AEP Power Pool members are also compensated for the out-of-pocket costs
of energy delivered to the AEP Power Pool and charged for energy received from
the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve
month peak demand relative to the total peak demand of all member companies as a
basis for sharing revenues and costs. The result of this calculation is each
company's member load ratio (MLR) which determines each company's percentage
share of revenues and costs.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to APCo as a member
of the AEP Power Pool. Trading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and the
buying and selling of financial energy contracts which include exchange traded
futures and options and over-the-counter options and swaps. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of open energy trading contracts.
Recording the net change in the fair value of open trading contracts
prior to settlement is commonly referred to as mark-to-market (MTM) accounting.
Under MTM accounting the change in the unrealized gain or loss throughout a
contract's term is recognized in each accounting period. When the contract
actually settles, that is, the energy is actually delivered in a sale or
received in a purchase or the parties agree to forego delivery and receipt and
net settle in cash, the unrealized gain or loss is reversed and the actual
realized cash gain or loss is recognized. Therefore, over the trading contract's
term an unrealized gain or loss is recognized as the contract's market value
changes. When the contract settles the total gain or loss is realized in cash
but only the difference between the accumulated unrealized net gains or losses
recorded in prior months and the cash proceeds is recognized. Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities.
The majority of our trading activities represent physical forward
electricity contracts that are typically settled by entering into offsetting
contracts. An example of our trading activities is when, in January, we enter
into a forward sales contract to deliver electricity in July. At the end of each
month until the contract settles in July, we would record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize a gain or loss in
cash and reverse to revenues the previously recorded cumulative unrealized gain
or loss.
Depending on whether the delivery point for the electricity is in
AEP's traditional marketing area or not determines where the contract is
reported on APCo's income statement. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory. Physical forward
trading sale contracts with delivery points in AEP's traditional marketing area
are included in revenues when the contracts settle. Physical forward trading
purchase contracts with delivery points in AEP's traditional marketing area are
included in purchased power expense when they settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are included in revenues on a net basis.
Physical forward sales contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating income when the contract settles.
Physical forward purchase contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating expenses when the contract settles.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of AEP's traditional marketing
area are included in nonoperating income on a net basis.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts from this point forward will have no further impact on
results of operations but will have an offsetting and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase contract prior to entering into a sales contract. If
the sale and purchase contracts do not match exactly as to volumes, delivery
point, schedule and other key terms, then there could be continuing
mark-to-market effects on results of operations from recording additional
changes in fair values using mark-to-market accounting.
Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior cumulative
unrealized net gain or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices at
settlement do not correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing APCo to market risk. See "Quantitative and
Qualitative Disclosures about Market Risk" section for a discussion of the
policies and procedures used to manage exposure to risk from trading activities.
Results of Operations
Net income decreased $6.4 million or 10% mainly due to the effect of
strong performance in 2001 by the wholesale business reflecting market
conditions that were more favorable than in 2002. Lower electricity demand in
the first quarter of 2002 depressed margins from wholesale electric marketing
and trading. APCo, as a member of the AEP Power Pool, shares in the revenues and
costs of wholesale marketing and trading activities conducted on ourits behalf by
the AEP Power Pool.
Net income
The following analyzes the changes in operating revenues:
Increase (Decrease)
(in millions) %
Electricity Marketing $(517) (29)
and Trading*
Energy Delivery* 3 2
Sales to AEP Affiliates (5) (11)
-----
Total $(519) (26)
=====
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The decrease in revenues was due primarily to reduced margins caused by
decreased $5.8 million or 16% forelectricity demand driven largely by mild weather and the quarter dueslow
recovery from the economic recession. Sales to a
decline in wholesale business performanceAEP affiliates declined as a
slowing economyresult of the mild weather and economic conditions that reduced demandelectricity
sales.
Operating expenses declined 27% in 2002. The changes in the components
of operating expenses were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Fuel $ 12 13
Electricity Marketing and
lowered wholesale electricity prices. Net incomeTrading Purchases (474) (32)
Purchases from AEP Affiliates (45) (42)
Other Operation 2 2
Maintenance (7) (22)
Depreciation and Amortization 3 7
Taxes Other Than Income Taxes - -
Income Taxes (3) (7)
-----
Total $(512) (27)
=====
Fuel expense increased $5.6 million or
5% for the year-to-date period primarily due to growth in and strong performance
by the wholesale business during the first half of 2001.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $479 31 $1,820 45
Fuel Expense 3 3 (8) (3)
Purchased Power Expense 475 40 1,778 60
Other Operation Expense 4 5 16 8
Maintenance Expense 2 8 12 14
Depreciation and Amortization 3 8 14 12
Federal Income Taxes (2) (13) 1 2
Nonoperating Income (3) (138) 5 80
Interest Charges (3) (9) (4) (4)
Extraordinary Gain - - (9) N.M.
N.M. = Not Meaningful
The significant increase in revenues for the quarter is due to a 69%
increase in trading volume partially offset by lower wholesale electricity
prices of our wholesale business. The significant year-to-date period increase
is due to a 44% increase in trading volume and an increase in wholesaleelectric generation as
certain plants that had undergone boiler plant maintenance in the first quarter
of 2001 were available for service in the first quarter of 2002.
The decline in electricity pricesmarketing and trading purchases was mainly
due to changes in market conditions. Expansion ofreduced prices caused by decreased electricity demand driven largely by
mild weather and the wholesale business' trading operation and greater liquidity in the market place
resulted in an increase in the number of forward electricity purchase and sales
contracts in AEP's traditional marketing area (up to two transmission systems
from AEP's service territory).
Fuel expense of the wholesale business increased for the quarter due to
a decrease in deferred fuel expense as compared to the previous quarter.economic recession.
The decrease in deferred fuelmaintenance expense is due to a lower average unit costthe effect of fuel.
Fuel expense decreased for the year-to-date period due to a decline in
generation as a result of scheduledboiler plant
maintenance.
For the quarter the increasemaintenance performed on certain plants in the wholesale business' purchased power
expense is attributable to an increase in trading volume partly offset by a
decrease in wholesale electricity prices. For the year-to-date period the
increase is attributable to increases in trading volumefirst quarter of 2001.
Depreciation and wholesale
electricity prices.
For the quarter other operation expense increased as a result of energy
delivery severance accruals and power trading incentive compensation expense of
the wholesale business. Year-to-date other operationamortization expense increased due to wholesale power trading incentive compensation expense.
The increasethe additional
accelerated amortization beginning in maintenance expense is mainly attributable to increased
generating plant boiler maintenance repairs toJuly 2001 of transition regulatory assets
in connection with the wholesale business' Amos,
Glen Lyn and Mountaineer Plants.
During June 2000 we discontinued the applicationdiscontinuance of SFAS 71 in the Virginia andCompany's West Virginia
jurisdictions. Consequentlyjurisdiction whereby net generation-related regulatory assets were transferred
to the energy delivery business' regulated
distribution portion of the business where the Virginia and West Virginia jurisdictions
authorized thecommensurate with their recovery of these assets
through regulated rates. Depreciation
and amortization expense increased due to the accelerated amortization beginning
in July 2000rates (see Note 5 for further discussion of the transition regulatory assets.effects of
restructuring). Additional investments in the
energy delivery business' distribution and transmissionproduction plant also
contributed to the increase in depreciation and amortization expense.
The decrease in federal income taxes for the quarter isfrom operations was due to a decrease in
pre-tax operating income.
Nonoperating income and expense decreased for the quarterlargely due to a net loss from the
wholesale business'reduced margins
on electricity trading transactions outside of the AEP System'sAEP's traditional marketing area caused by
decreased electricity demand resulting from mild weather and speculative financial transactions (options, futures, swaps).
Duethe slow recovery
from the economic recession.
Interest charges decreased due primarily to significant net gains in the first six monthsincreased allowances for
borrowed funds as a result of 2001 on these wholesale
trading transactions, nonoperating income increased in the year-to-date period.
The interest charge decrease is due toconstruction expenditures and the
retirement of first mortgage bonds on March 1, 2001 and the retirement of senior
unsecured notes in 2000.June 2001.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $2,017,159 $1,538,340 $5,840,590 $4,020,792
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 91,594 88,769 272,119 279,989
Purchased Power 1,666,443 1,191,737 4,765,476 2,987,568
Other Operation 76,197 72,297 210,034 194,504
Maintenance 31,812 29,369 98,663 86,683
Depreciation and Amortization 46,177 42,798 133,950 120,035
Taxes Other Than Federal Income Taxes 29,275 30,088 91,118 89,550
Federal Income Taxes 15,280 17,532 61,335 60,259
------ ------ ------ ------
TOTAL OPERATING EXPENSES 1,956,778 1,472,590 5,632,695 3,818,588
--------- --------- --------- ---------
OPERATING INCOME 60,381 65,750 207,895 202,204
NONOPERATING INCOME (LOSS) (918) 2,399 11,905 6,607
---- ----- ------ -----
INCOME BEFORE INTEREST CHARGES 59,463 68,149 219,800 208,811
INTEREST CHARGES 29,146 32,037 91,277 94,795
------ ------ - ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 30,317 36,112 128,523 114,016
EXTRAORDINARY GAIN - DISCONTINUANCE OF SFAS 71
(INCLUSIVE OF TAX BENEFIT OF $7,872,000)
- - - 8,938
------- ------- ------- -----
NET INCOME 30,317 36,112 128,523 122,954
PREFERRED STOCK
DIVIDEND REQUIREMENTS 502 750 1,508 2,015
--- --- ----- -----
EARNINGS APPLICABLE TO
COMMON STOCK $ 29,815 $ 35,362 $ 127,015 $ 120,939
==========- ==========APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $1,257,355 $1,773,894
Energy Delivery 154,995 152,097
Sales to AEP Affiliates 42,806 48,136
---------- ----------
TOTAL OPERATING REVENUES 1,455,156 1,974,127
---------- ----------
OPERATING EXPENSES:
Fuel 107,490 95,476
Purchased Power:
Electricity Marketing and Trading 1,005,599 1,479,528
AEP Affiliates 60,780 105,674
Other Operation 67,427 65,889
Maintenance 25,851 33,009
Depreciation and Amortization 46,772 43,717
Taxes Other Than Income Taxes 24,995 25,428
Income Taxes 34,688 37,254
---------- ----------
TOTAL OPERATING EXPENSES 1,373,602 1,885,975
---------- ----------
OPERATING INCOME 81,554 88,152
NONOPERATING INCOME 400,172 465,405
NONOPERATING EXPENSES 398,733 458,205
NONOPERATING INCOME TAX EXPENSE 264 2,149
INTEREST CHARGES 27,388 31,416
---------- ----------
NET INCOME 55,341 61,787
PREFERRED STOCK DIVIDEND REQUIREMENTS 503 503
---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 54,838 $ 61,284
========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME $30,317 $36,112 $128,523 $122,954
OTHER COMPREHENSIVE INCOME
Foreign Currency Exchange Rate Hedge 673 - 44 -
--- ------- -- -
COMPREHENSIVE INCOME $30,990 $36,112 $128,567 $122,954CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
NET INCOME $55,341 $61,787
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge 143 (417)
------- -------
COMPREHENSIVE INCOME $55,484 $61,370
======= =======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $150,797 $120,584
NET INCOME 55,341 61,787
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 30,984 32,399
Cumulative Preferred Stock 361 361
Capital Stock Expense 142 142
-------- --------
BALANCE AT END OF PERIOD $174,651 $149,469
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $152,987 $198,126 $120,584 $175,854
NET INCOME 30,317 36,112 128,523 122,954
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 32,399 31,653 97,196 94,959
Cumulative Preferred Stock 361 375 1,082 1,425
Capital Stock Expense 141 375 426 589
--- --- --- ---
BALANCE AT END OF PERIOD $150,403 $201,835 $150,403 $201,835
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,084,311 $2,093,532
Transmission 1,212,470 1,222,226
Distribution 1,889,828 1,887,020
General 260,110 257,957
Construction Work in Progress 267,720 203,922
---------- ----------
Total Electric Utility Plant 5,714,439 5,664,657
Accumulated Depreciation and Amortization 2,326,515 2,296,481
---------- ----------
NET ELECTRIC UTILITY PLANT 3,387,924 3,368,176
---------- ----------
OTHER PROPERTY AND INVESTMENTS 51,497 53,736
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 521,221 316,249
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents - 13,663
Accounts Receivable:
Customers 120,599 113,371
Affiliated Companies 98,805 63,368
Miscellaneous 20,983 11,847
Allowance for Uncollectible Accounts (2,259) (1,877)
Fuel - at average cost 50,582 56,699
Materials and Supplies - at average cost 53,307 59,849
Accrued Utility Revenues 23,894 30,907
Energy Trading Contracts 766,378 566,284
Prepayments 21,694 16,018
---------- ----------
TOTAL CURRENT ASSETS 1,153,983 930,129
---------- ----------
REGULATORY ASSETS 391,518 397,383
---------- ----------
DEFERRED CHARGES 45,939 42,265
---------- ----------
TOTAL ASSETS $5,552,082 $5,107,938
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,072,425 $2,058,952
Transmission 1,214,697 1,177,079
Distribution 1,862,101 1,816,925
General 258,285 254,371
Construction Work in Progress 151,705 110,951
------- -------
Total Electric Utility Plant 5,559,213 5,418,278
Accumulated Depreciation and Amortization 2,271,949 2,188,796
--------- ---------
NET ELECTRIC UTILITY PLANT 3,287,264 3,229,482
--------- ---------
OTHER PROPERTY AND INVESTMENTS 55,992 56,967
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 370,807 322,688
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 28,766 5,847
Advances to Affiliates - 8,387
Accounts Receivable:
Customers 132,169 243,298
Affiliated Companies 68,088 63,919
Miscellaneous 17,285 16,179
Allowance for Uncollectible Accounts (1,868) (2,588)
Fuel - at average cost 47,862 39,076
Materials and Supplies - at average cost 60,891 57,515
Accrued Utility Revenues 19,844 66,499
Energy Trading Contracts 918,417 2,036,001
Prepayments 13,364 6,307
------ -----
TOTAL CURRENT ASSETS 1,304,818 2,540,440
--------- ---------
REGULATORY ASSETS 439,075 447,750
------- -------
DEFERRED CHARGES 26,940 48,826
------ ------
TOTAL ASSETS $5,484,896 $6,646,153
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001 December 31, 2000
------------------ -----------------
(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 715,644 715,218715,928 715,786
Accumulated Other Comprehensive Income 44 -(Loss) (197) (340)
Retained Earnings 150,403 120,584
------- -------174,651 150,797
---------- ----------
Total Common Shareowner's Equity 1,126,549 1,096,2601,150,840 1,126,701
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 17,790
Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,506,285 1,430,812
--------- ---------1,476,819 1,476,552
---------- ----------
TOTAL CAPITALIZATION 2,661,484 2,555,722
--------- ---------2,656,309 2,631,903
---------- ----------
OTHER NONCURRENT LIABILITIES 89,099 105,883
------ -------84,672 84,104
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 50,007 175,006
Short-term Debt - 191,49580,007 80,007
Advances from Affiliates 209,538 -259,826 291,817
Accounts Payable - General 139,439 153,422100,440 131,387
Accounts Payable - Affiliated Companies 86,989 107,556126,921 84,518
Taxes Accrued 77,888 63,25884,712 55,583
Customer Deposits 17,225 12,61214,874 13,177
Interest Accrued 40,659 21,55539,286 21,770
Energy Trading Contracts 863,309 2,091,804740,311 549,703
Other 80,355 85,378
------ ------71,916 75,299
---------- ----------
TOTAL CURRENT LIABILITIES 1,565,409 2,902,086
--------- ---------1,518,293 1,303,261
---------- ----------
DEFERRED INCOME TAXES 720,630 682,474
------- -------700,120 703,575
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 39,775 43,093
------ ------37,230 38,328
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 319,544 259,438
------- -------463,896 257,129
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 88,955 97,457
------ ------91,562 89,638
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,484,896 $6,646,153$5,552,082 $5,107,938
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 128,52355,341 $ 122,95461,787
Adjustments for Noncash Items:
Depreciation and Amortization 134,034 120,11946,800 43,745
Deferred Federal Income Taxes 27,227 14,059(3,644) 19,438
Deferred Investment Tax Credits (3,318) (3,446)(1,098) (1,106)
Deferred Power Supply Costs (net) 131 (80,232)
Amortization352 121
Mark to Market of Deferred Property Taxes 13,480 13,051
Extraordinary Gain - Discontinuance of SFAS 71 - (8,938)Energy Trading Contracts (6,653) (59,398)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 105,134 (99,426)(51,419) 82,071
Fuel, Materials and Supplies (12,162) 8,91912,659 3,091
Accrued Utility Revenues 46,655 12,9487,013 51,292
Accounts Payable (34,550) 101,57111,456 6,086
Taxes Accrued 14,630 14,08429,129 5,417
Interest Accrued 19,104 16,345
Net17,516 17,618
Change in Energy Trading Contracts (98,924) (13,446)
Rate Stabilization Deferral - 75,601
Other (net) (10,782) (24,757)
------- -------Assets (7,043) (16,226)
Change in Other Liabilities 1,366 (2,789)
--------- ---------
Net Cash Flows From Operating Activities 329,182 269,406
------- -------111,775 211,147
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (185,185) (132,290)(62,685) (39,922)
Proceeds from Sale of Property 583 1,182
160
----- ------------ ---------
Net Cash Flows Used For Investing Activities (184,003) (132,130)
-------- --------(62,102) (38,740)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 124,588 74,788
Change in Short-term Debt (net) - (191,495) (23,455)
Change in Advance fromAdvances From Affiliates (net) 217,925 (8,626)
Retirement of Cumulative Preferred Stock - (9,905)(31,991) 153,572
Retirement of Long-term Debt (175,000) (131,202)- (100,000)
Dividends Paid on Common Stock (97,196) (94,959)(30,984) (32,399)
Dividends Paid on Cumulative Preferred Stock (1,082) (1,578)
------ ------(361) (361)
--------- ---------
Net Cash Flows Used For Financing Activities (122,260) (194,937)
-------- --------(63,336) (170,683)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 22,919 (57,661)(13,663) 1,724
Cash and Cash Equivalents at Beginning of Period 13,663 5,847
64,828
----- --------------- ---------
Cash and Cash Equivalents at End of Period $ 28,766- $ 7,167
==========7,571
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $70,286,000$9,222,000 and $75,938,000$13,156,000
and for income taxes was $21,521,000$9,593,000 and $30,503,000$13,543,000 in 20012002 and 2000,2001,
respectively. Noncash acquisitions under capital leases were $2,576,000$-0- and $11,312,000$1,512,000
in 20012002 and 2000,2001, respectively.
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARYSUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses:CPL is a public utility engaged in the generation, sale, transmission and
distribution of electric power in southern Texas. CPL also sells electric power
at wholesale which consiststo other utilities, municipalities, rural electric cooperatives and
beginning in 2002 to retail electric providers (REPs) in Texas, (see
"Introduction of generation, retail
electricity sales,Customer Choice" section below).
Wholesale power marketing and trading activities are conducted on CPL's
behalf by AEPSC. CPL shares in the revenues and costs of electricity;forward trades with
other utility systems and energy
delivery, which consistspower marketers.
Introduction of Customer Choice
- -------------------------------
On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas. CPL currently
operates in the ERCOT region of Texas.
Under the Texas Restructuring Legislation, each electric utility was
required to submit a plan to structurally unbundle its business into a retail
electric provider, a power generator, and a transmission and distribution
services. Sinceutility. During the mergeryear 2000, CPL submitted a plan for separation that was
subsequently approved by the PUCT. As a result of this legislation, CPL has
functionally separated its generation from its transmission and distribution
operations and formed a separate REP. Pending regulatory approval, CPL will
corporately separate its generation from its transmission and distribution
operations. The REP is a separate legal entity that is a subsidiary of AEP and
CSW in June 2000, we participateis not owned by or consolidated with CPL.
Since the REP is the electricity supplier to retail customers in the
ERCOT area, CPL sells its generation to the REP and provides transmission and
distribution services to retail customers in its ERCOT service territory. As a
result of the formation of the REP, CPL no longer supplies electricity to retail
customers in the ERCOT area. Instead CPL sells its generation to the REP. The
implementation of REPs as suppliers to retail customers has caused a significant
shift in CPL's sales as described below under "Results of Operations."
Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a
result of our cost-based rate-regulated transmission and distribution
operations, our financial statements reflect the actions of regulators that can
result in the recognition of revenues and expenses in different time periods
than enterprises that are not rate regulated. In accordance with SFAS 71,
regulatory assets (deferred expenses) and regulatory liabilities (future revenue
reductions or refunds) are recorded to reflect the economic effects of
regulation by matching expenses with their recovery through regulated revenues
in the same accounting period.
When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates. Traditional Electricity
Supply and Delivery Activities - We recognize revenues on an accrual basis for
electricity supply sales and electricity transmission and distribution delivery
services. The revenues are recognized in our income statement when the energy is
delivered to the customer and include unbilled as well as billed amounts. In
general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP System's powerengages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to CPL. Trading
activities allocated to CPL involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of open energy trading contracts.
Recording the net change in the fair value of open trading contracts
as revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. Under MTM accounting the change in the unrealized gain or loss
throughout a contract's term is recognized in each accounting period. When the
contract actually settles, that is, the energy is actually delivered in a sale
or received in a purchase or the parties agree to forego delivery and receipt of
electricity and net settle in cash, the unrealized gain or loss is reversed out
of revenues and the actual realized cash gain or loss is recognized in revenues
for a sale or in purchased power expense for a purchase. Therefore, over the
trading contract's term an unrealized gain or loss is recognized as the
contract's market value changes. When the contract settles the total gain or
loss is realized in cash but only the difference between the accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized. Unrealized mark-to-market gains and losses are included in the
Balance Sheet as energy trading contract assets or liabilities.
Our trading activities represent physical forward electricity contracts
that are typically settled by entering into offsetting contracts. An example of
our trading activities is when, in January, we enter into a forward sales
contract to deliver electricity in July. At the end of each month until the
contract settles in July, we would record our share of any difference between
the contract price and the market price as an unrealized gain or loss in
revenues. In July when the contract settles, we would realize our share of a
gain or loss in cash and reverse to revenues the previously recorded cumulative
unrealized gain or loss. Prior to settlement, the change in the fair value of
physical forward sale and purchase contracts is included in revenues on a net
basis. Upon settlement of a forward trading contract, the amount realized is
included in revenues for a sales contract and the realized cost is included in
purchased power expense for a purchase contract with the prior change in
unrealized fair value reversed in revenues.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts from this point forward will have no further impact on
results of operations but will have an offsetting and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase contract prior to entering into a sales contract. If
the sale and purchase contracts do not match exactly as to volumes, delivery
point, schedule and other key terms, then there could be continuing
mark-to-market effects on revenues from recording additional changes in fair
values using mark-to-market accounting.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices at
settlement do not correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing CPL to market risk. See "Quantitative and
Qualitative Disclosure About Market Risk" section for a discussion of the
policies and procedures used to manage exposure to risk from trading activities.
Third quarter netResults of Operations
Net income decreased $6$10.6 million, or 7% while year-to-date
net income increased $6 million or 3%. The lower third quarter net income was30%, primarily due to weak performancemild
winter weather and a slow recovery from marketingthe economic recession. Operating
revenues decreased $200 million for the quarter as shown below:
Increase (Decrease)
(in millions) %
Electricity Marketing
and trading. Year-to-date net income
increased primarily from our participationTrading* $(361) (76)
Energy Delivery* 2 2
Sales to AEP Affiliates 159 N.M.
-----
Total $(200) (33)
=====
*Reflects the allocation of certain transmission and distribution
revenues included in AEP's powerbundled retail rates to energy delivery.
N.M. = Not Meaningful
Electricity marketing and trading operations duringrevenues decreased $361 million as a
result of several factors, including the first halfelimination of 2001 compared with 2000 when we did not
shareretail sales in AEP's power marketingthe
ERCOT area as of January 1, 2002, a decrease in energy trading, and trading.
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $440 55 $938 61
Fuel Expense (60) (33) 9 2
Purchased Power Expense 526 195 906 278
Other Operation Expense (28) (27) (6) (3)
Maintenance 1 8 4 10
Depreciation and Amortization (9) (21) (8) (6)
Taxes Other Than Federal Income Taxes 21 107 25 43
Federal Income Taxes (3) (7) 4 4
Nonoperating Income 3 333 - -
mild winter
weather.
The significant increase in revenues for the quarter resulted from
increased trading volumes of the wholesale business. In the year-to-date period,
the increase in revenuesSales to AEP Affiliates is also attributable to our participation in AEP's
power marketing and trading operations and higher fuel related revenues due to increased coststhe
introduction on January 1, 2002 of fuelcustomer choice of electricity supplier which
resulted in CPL selling power at wholesale to a new affiliated REP.
Operating expenses declined 36% in 2002. The changes in the components of
operating expenses were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Fuel $ (98) (64)
Electricity Marketing and
purchased power.Trading Purchases (73) (36)
Purchases from AEP Affiliates (5) (38)
Other Operation (9) (12)
Maintenance (6) (37)
Depreciation and Amortization - -
Taxes Other Than Income Taxes 8 43
Income Taxes (8) (44)
-----
Total $(191) (36)
=====
Fuel expense decreased for the quarter primarily due to a significant decrease in the average unit cost of
fuel as a result ofresulting from lower spot market natural gas prices.
Year-to-date fuel expense was up due primarily to an
increase in the average unit cost of fuel as a result of higher spot market
natural gas prices in the first and second quarters.
The substantial rise in purchased power expense for both the quarter
and year-to-date periods was attributable to our participation in AEP's powerElectricity marketing and trading operation.
Other operation expense for the quarterpurchases decreased due to a decline
in demand for electricity due to the slow economic recovery and the mild winter
weather.
The decrease in maintenance and other operation expenses resulted from
the effects of a STP nuclear refueling outage in 2001.
Taxes other than income taxes increased due to the effect of a
favorable accrual adjustment in 2001 for ad valorem taxes.
The decrease in income tax expense attributable to operations
in 2002 was primarily due to a decrease in transmission expenses. Additionally, production expenses were down
due to decreased power trading incentive compensation expense.
Maintenance for the quarter increased due to the preparatory expenses
for an October STP Unit 1 nuclear refueling outage. A nuclear refueling outage
for STP Unit 2 between March 7 and April 2, 2001 also contributed to the
increase in year-to-date maintenance expense. STP Unit 1 completed its refueling
outage and returned to service October 25, 2001.
The decrease in depreciation and amortization expense for the quarter
is due primarily to lower excess earnings provisions under Texas Restructuring
Legislation. Year-to-date depreciation and amortization expense also decreased
due to accelerated ECOM depreciation on STP ceasing in July 2000.
Taxes other than federal income taxes increased due primarily to an
increase in franchise related taxes, including a settlement of disputed
franchise fees (see Note 8), and Texas assessment taxes, a new tax levied by the
PUCT.
Federal income taxes attributable to operations decreased for the
quarter and increased for the year-to-date period due to a decrease and
increase, respectively, in pre-tax operating income.
Nonoperating income for the quarter increased due
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES:
Electric Marketing and Trading $111,435 $472,294
Energy Delivery 112,127 110,330
Sales to interest income on
underrecovered fuel costsAffiliates 179,661 20,788
-------- --------
Total Operating Revenues 403,223 603,412
-------- --------
OPERATING EXPENSES:
Fuel 54,328 151,853
Purchased Power:
Electric Marketing and was partially offset by a decrease in interest
income on the Decommissioning Trust Fund.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,235,941 $795,794 $2,487,852 $1,550,033
---------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 121,933 181,827 420,965 412,065
Purchased Power 795,448 269,823 1,230,786 325,179
Other Operation 73,543 101,116 224,803 230,725
Maintenance 13,827 12,780 49,109 44,676
Depreciation and Amortization 33,257 41,970 129,235 137,055
Taxes Other Than Federal Income Taxes 40,735 19,717 81,934 57,173
Federal Income Taxes 44,600 47,908 91,919 88,140
------ ------ ------ ------
TOTAL OPERATING EXPENSES 1,123,343 675,141 2,228,751 1,295,013
--------- ------- --------- ---------
OPERATING INCOME 112,598 120,653 259,101 255,020
NONOPERATING INCOME (LOSS) 3,540 818 3,638 3,180
----- --- ----- -----
INCOME BEFORE INTEREST CHARGES 116,138 121,471 262,739 258,200
INTEREST CHARGES 32,436 31,497 91,488 92,534
------ ------ ------ ------
NET INCOME 83,702 89,974 171,251 165,666
PREFERRED STOCK DIVIDEND REQUIREMENTS
60 60 181 181
-- -- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 83,642 $ 89,914 $ 171,070 $165,485
======== ======== ==========Trading 128,325 201,796
Affiliates 7,927 12,770
Other Operation 65,986 75,071
Maintenance 10,959 17,287
Depreciation and Amortization 41,847 42,391
Taxes Other Than Income Taxes 27,922 19,488
Income Taxes 10,484 18,604
-------- --------
TOTAL OPERATING EXPENSES 347,778 539,260
-------- --------
OPERATING INCOME 55,445 64,152
NONOPERATING INCOME 9,531 3,199
NONOPERATING EXPENSES 9,387 837
NONOPERATING INCOME TAX EXPENSE 133 723
INTEREST CHARGES 31,011 30,760
-------- --------
NET INCOME 24,445 35,031
PREFERRED STOCK DIVIDEND REQUIREMENTS 60 60
-------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 24,385 $ 34,971
========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $805,619 $756,465 $792,219 $758,894
NET INCOME 83,702 89,974 171,251 165,666
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 37,015 39,000 111,043 117,000
Preferred Stock 60 61 181 182
-- -- --- ---
BALANCE AT END OF PERIOD $852,246 $807,378 $852,246 $807,378
======== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $826,197 $792,219
NET INCOME 24,445 35,031
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 38,502 37,014
Preferred Stock 60 60
Other - 1
-------- --------
BALANCE AT END OF PERIOD $812,080 $790,175
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARYSUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $3,165,533 $3,175,867$3,171,938 $3,169,421
Transmission 646,264 581,931693,317 663,655
Distribution 1,272,057 1,221,7501,294,074 1,279,037
General 244,803 237,764244,361 241,137
Construction Work in Progress 164,633 138,273134,133 169,075
Nuclear Fuel 245,745 236,859
------- -------247,393 247,382
---------- ----------
Total Electric Utility Plant 5,739,035 5,592,4445,785,216 5,769,707
Accumulated Depreciation and Amortization 2,395,951 2,297,189
--------- ---------2,476,402 2,446,027
---------- ----------
NET ELECTRIC UTILITY PLANT 3,343,084 3,295,255
--------- ---------3,308,814 3,323,680
---------- ----------
OTHER PROPERTY AND INVESTMENTS 47,099 44,225
------ ------48,989 47,950
---------- ----------
SECURITIZED TRANSITION ASSET 758,436 -
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 86,270 66,231
------ ------32,259 72,502
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 6,706 14,2539,206 10,909
Accounts Receivable:
Customers 74,642 67,787General 52,545 38,459
Affiliated Companies 13,295 31,27261,588 6,249
Allowance for UncollectibleUncollectable Accounts (447) (1,675)(211) (186)
Fuel Inventory - at LIFO cost 36,111 22,84238,572 38,690
Materials and Supplies - at average cost 55,700 53,108
Under-recovered Fuel Costs 10,822 127,29556,952 55,475
Energy Trading Contracts 314,177 481,20656,534 212,979
Prepayments and Other Current Assets 4,357 3,014
----- -----6,967 2,742
---------- ----------
TOTAL CURRENT ASSETS 515,363 799,102
------- -------282,153 365,317
---------- ----------
REGULATORY ASSETS 234,038 202,440
------- -------227,140 226,806
---------- ----------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 953,249 953,249
------- -------179,384 959,294
---------- ----------
NUCLEAR DECOMMISSIONING TRUST FUND 91,859 93,592
------ ------100,763 98,600
---------- ----------
DEFERRED CHARGES 21,367 18,402
------ ------83,596 21,837
---------- ----------
TOTAL ASSETS $5,292,329 $5,472,496$5,021,534 $5,115,986
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARYSUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 2,211,678 shares at March 31, 2002
6,755,535 Shares at December 31, 2001 $ 168,88855,292 $ 168,888
Paid-in Capital 405,000132,592 405,000
Retained Earnings 852,246 792,219
------- -------812,080 826,197
---------- ----------
Total Common Shareowner's Equity 1,426,134 1,366,107999,964 1,400,085
Preferred Stock 5,967 5,967
CPL - Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of CPL 136,250 148,500136,250
Long-term Debt 942,865 1,254,559
------- ---------1,736,183 988,768
---------- ----------
TOTAL CAPITALIZATION 2,511,216 2,775,133
--------- ---------2,878,364 2,531,070
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 511,700 200,000164,200 265,000
Advances from Affiliates 57,722 269,712238,830 354,277
Accounts Payable - General 125,578 128,95737,545 65,307
Accounts Payable - Affiliated Companies 14,118 40,96244,028 49,301
Customer Deposits 2,204 26,744
Over Recovered Fuel 58,956 57,762
Taxes Accrued 219,657 55,526101,279 83,512
Interest Accrued 23,339 26,21728,035 18,524
Energy Trading Contracts 314,346 489,88861,628 219,486
Other 46,712 40,630
------ ------16,278 22,768
---------- ----------
TOTAL CURRENT LIABILITIES 1,313,172 1,251,892
--------- ---------752,983 1,162,681
---------- ----------
DEFERRED INCOME TAXES 1,186,803 1,242,797
--------- ---------1,157,840 1,163,795
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 124,194 128,100
------- -------121,591 122,892
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 87,095 65,740
------ ------29,774 62,138
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 69,849 8,834
------ -----80,982 73,410
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,292,329 $5,472,496$5,021,534 $5,115,986
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARYSUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 171,25124,445 $ 165,66635,031
Adjustments for Noncash Items:
Depreciation and Amortization 129,235 137,05541,847 42,391
Deferred Federal Income Taxes (50,506) 14,529(8,083) 2,579
Deferred Investment Tax Credits (3,905) (3,905)(1,302) (1,302)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 9,894 (30,689)(69,400) 8,203
Fuel, Materials and Supplies (15,861) 5,829(1,359) (15,468)
Fuel Recovery 116,473 (89,733)1,194 2,073
Electricity Mark to Market 6,466 (9,260)
Accounts Payable (30,223) 80,539(33,035) (18,115)
Taxes Accrued 164,131 30,147
Transmission Coordination Agreement Settlement - 15,51917,767 27,571
Deferred Property Taxes (8,063) - (29,292)
Change in Other (net) 4,257 3,396
----- -----Assets (53,865) (43,099)
Change in Other Liabilities (11,978) 22,934
--------- --------
Net Cash Flows From (Used For) Operating Activities 486,683 328,353
------- -------(87,303) 24,246
--------- --------
INVESTING ACTIVITIES:
Construction Expenditures (158,191) (137,053)(21,002) (38,873)
Other - (354)
-
---- ---------------- --------
Net Cash Flows Used For Investing Activities (158,545) (137,053)
--------(21,002) (39,227)
--------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 796,613 - 149,413
Retirement of Long-term Debt - (100,000)
Reacquisition(149,998) (505)
Retirement of Long-term DebtCommon Stock (386,004) - (50,000)
Reacquisition of Trust Preferred Securities (12,471) (1,440)
Change in Advances from Affiliates (net) (211,990) (123,836)
Special Deposit for Reacquisitions of Long-term Debt - 50,000(115,447) 43,156
Dividends Paid on Common Stock (111,043) (117,000)(38,502) (37,014)
Dividends Paid on Cumulative Preferred Stock (181) (188)
---- ----(60) (60)
--------- --------
Net Cash Flows Used ForFrom Financing Activities (335,685) (193,051)
--------106,602 5,577
--------- --------
Net Decrease in Cash and Cash Equivalents (7,547) (1,751)(1,703) (9,404)
Cash and Cash Equivalents at Beginning of Period 10,909 14,253
7,995
------ -------------- --------
Cash and Cash Equivalents at End of Period $ 6,7069,206 $ 6,2444,849
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $80,612,000========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $18,505,000 and
$24,938,000 and for income taxes was $18,482,000 and $6,071,000 in 2002 and
$81,211,000 and for income taxes was $11,939,000 and $48,141,000 in
2001, and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists ofColumbus Southern Power Company is a public utility engaged in the
generation, marketing and trading of electricity; and energy delivery which consists ofpurchase, sale, transmission and distribution services. We belongof electric power to
678,000 retail customers in central and southern Ohio. CSPCo as a member of the
AEP Power Pool shares in the revenues and costs of the AEP Power Pool's
wholesale sales to neighboring utility systems and power marketers including
power trading transactions. CSPCo also sells wholesale power to municipalities.
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 receipt of capacity credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing AEP Power Pool revenues and costs. The result of this calculation is the
member load ratio (MLR) which determines each company's percentage share of AEP
Power Pool revenues and costs.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of wholesale marketing andAEP's trading activities conducted on our behalf byare allocated to CSPCo as a
member of the AEP Power Pool. Net income increased $25 million or 62%Trading activities involve the purchase and sale
of energy under physical forward contracts at fixed and variable prices and the
buying and selling of financial energy contracts which include exchange traded
futures and options and over-the-counter options and swaps. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
third quarterfair value of 2001 dueopen energy trading contracts.
Recording the net change in the fair value of open trading contracts
prior to settlement is commonly referred to as mark-to-market (MTM) accounting.
Under MTM accounting the effectchange in the unrealized gain or loss throughout a
contract's term is recognized in each accounting period. When the contract
actually settles, that is, the energy is actually delivered in a sale or
received in a purchase or the parties agree to forego delivery and receipt and
net settle in cash, the unrealized gain or loss is reversed and the actual
realized cash gain or loss is recognized. Therefore, over the trading contract's
term an unrealized gain or loss is recognized as the contract's market value
changes. When the contract settles the total gain or loss is realized in cash
but only the difference between the accumulated unrealized net gains or losses
recorded in prior months and the cash proceeds is recognized. Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities.
The majority of our trading activities represent physical forward
electricity contracts that are typically settled by entering into offsetting
contracts. An example of our trading activities is when, in January, we enter
into a forward sales contract to deliver electricity in July. At the end of each
month until the contract settles in July, we would record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of a prior period $25 million extraordinarygain
or loss in cash and reverse the previously recorded cumulative unrealized gain
or loss.
Income before
extraordinary itemDepending on whether the delivery point for the third quarter of 2001 was flat. Net income increased
$21 million or 20% and income before extraordinary item increased $22 million or
17% for the year-to-date period, due to the strength and growth of the wholesale
business during the first half of 2001.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $337 35 $1,010 40
Fuel Expense (8) (15) (8) (5)
Purchased Power Expense 343 52 960 55
Other Operation Expense - - 14 9
Maintenance Expense (4) (20) 2 4
Depreciation and Amortization 7 29 21 28
Taxes Other Than Federal Income Taxes 5 17 8 8
Nonoperating Income 6 N.M. 8 N.M.
Extraordinary Loss (25) N.M. 1 5
N.M. = Not Meaningful
The significant increase in revenues for the quarterelectricity is due to an 86%
increase in trading volume partially offset by lower wholesale electricity
prices. The significant year-to-date increase is due to a 41% increase in
wholesale trading volume and an increase in wholesale electricity prices due to
changes in market conditions. Expansion of the wholesale business' trading
operation and greater liquidity in the market place resulted in an increase in
the number of forward electricity purchase and sales contracts made in
AEP's traditional marketing area (upor not determines where the contract is
reported on CSPCo's income statement. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory. Physical forward
trading sale contracts with delivery points in AEP's service
territory).
Fueltraditional marketing area
are included in revenues when the contracts settle. Physical forward trading
purchase contracts with delivery points in AEP's traditional marketing area are
included in purchased power expense when they settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are included in revenues on a net basis.
Physical forward sales contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating income when the contract settles.
Physical forward purchase contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating expenses when the contract settles.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of AEP's traditional marketing
area are included in nonoperating income on a net basis.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the wholesale businesstwo contracts. Mark-to-market accounting
for these contracts from this point forward will have no further impact on
results of operations but will have an offsetting and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase contract prior to entering into a sales contract. If
the sale and purchase contracts do not match exactly as to volumes, delivery
point, schedule and other key terms, then there could be continuing
mark-to-market effects on results of operations from recording additional
changes in fair values using mark-to-market accounting.
Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior cumulative
unrealized net gain or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due. Liquidity risk represents the risk that imperfections in the market
will cause the price to be less than or more than what the price should be based
purely on supply and demand. There are inherent risks related to the underlying
assumptions in models used to fair value open long-term trading contracts. AEP
has independent controls to evaluate the reasonableness of our valuation models.
However, energy markets, especially electricity markets, are imperfect and
volatile and unforeseen events can and will cause reasonable price curves to
differ from actual prices throughout a contract's term and when contracts
settle. Therefore, there could be significant adverse or favorable effects on
future results of operations and cash flows if market prices at settlement do
not correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing CSPCo to market risk. See "Quantitative and
Qualitative Disclosures about Market Risk" section for a discussion of the
policies and procedures used to manage exposure to risk from trading activities.
Results of Operations
Net income decreased $3.8 million or 10% due to depressed margins from
electric marketing and trading caused by lower energy demand in the first
quarter of 2002. Earnings from electric marketing and trading were much stronger
in the first quarter of 2001 than in recent months due to milder weather and the
slow recovery from the economic recession.
The decline in revenues is mainly due to a decrease in net generation partially offsetelectric
marketing and trading revenues. The following analyzes the changes in operating
revenues:
Increase (Decrease)
(in millions) %
Electricity Marketing
And Trading* $(168.7) (17)
Energy Delivery* 3.6 4
Sales to AEP Affiliates (11.1) (59)
-------
Total $(176.2) (16)
=======
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The decrease in electric marketing and trading was driven largely by an increasea
decline in demand due to mild winter weather and the slow recovery from the
economic recession. Heating degree days for the first quarter of 2002 were down
11.8% from the same quarter last year. Electricity sales to industrial customers
decreased 4%.
Operating expenses declined 16% in 2002. The changes in the average unit pricecomponents
of fueloperating expenses were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Fuel $ (1.4) (3)
Electricity Marketing and
the discontinuance of deferred fuel accounting effective January 1, 2001
because of deregulation. In 2000Trading Purchases (161.7) (20)
Purchases from AEP Affiliates (0.7) (1)
Other Operation (0.4) (1)
Maintenance (4.6) (25)
Depreciation and Amortization 1.3 4
Taxes Other Than Income Taxes (0.4) (1)
Income Taxes (5.8) (25)
-------
Total $(173.7) (16)
=======
The decrease in fuel expense included chargeswas primarily attributable to a reduction
in generation of 4.6% due to the reduced demand for electricity.
Electricity marketing and trading purchases also declined due to reduced
demand, a continuation of the amortization of previously deferred fuel costs. The amortization was concurrent
with recovery through fuel clause revenues.
For the quarter the increasemarket conditions that developed in the wholesale business' purchased power
expense is attributable to an increasefourth
quarter of 2001.
Maintenance expenses decreased in trading volume offset by a decrease in
wholesale electricity prices. For the year-to-date period the increase was
attributable to increases in trading volume and wholesale electricity prices
Other operation expense increased year-to-date due to increases in
uncollectible accounts, factored customer accounts receivable expenses, the
effectfirst quarter of gains in 2000 from the disposition of emission allowances, higher
power trading expenses and trading incentive compensation and energy delivery
severance accruals.
For the quarter, maintenance expenses decreased2002 due to
boiler overhaulsoverhaul work that was performed during the first quarter of 2001.
Expenses for maintaining distribution overhead lines and maintenance of overhead energy deliveryunderground lines completedwere
also lower in the prior period.
The commencement of the amortization of transition regulatory assets2002.
A decrease in connection with the transition to customer choice and market-based pricing of
electricity under Ohio deregulation accounted for the increase in depreciation
and amortization expense.
The increase in taxes other thanpre-tax operating income caused income taxes is dueattributable
to a new state
excise tax which produces a larger tax than the gross receipts tax it replaced.operations to decline.
The increase in nonoperating income which was offset by a larger
increase in non-operating expenses was due to an increasea reduction in net gains from the wholesale business'AEP
Power Pool trading transactions outside of the AEP System's traditional
marketing area. The AEP Power Pool enters into power trading transactions for
the purchase and sale of electricity and for options, futures and swaps. The
Company's share of the AEP Power Pool's gains and losses from forward
electricity trading transactions outside of the AEP System traditional marketing
area and for speculative financial transactions (options, futures, swaps) is
included in nonoperating income and swaps).
Inexpense. The decrease reflects a reduction
in electricity prices and margins due to a decrease in demand reflecting milder
weather and the secondslow economic recovery.
The decrease in interest was primarily due to a decrease in the
outstanding balance of long-term debt since the first quarter of 2001, we recorded an extraordinary lossthe
refinancing of $26
million net of taxdebt at favorable interest rates and a reduction in short-term
interest rates.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $ 839,089 $1,007,831
Energy Delivery 102,548 98,996
Sales to write-off prepaid Ohio excise taxes stranded by Ohio
deregulation (see Note 2). The application of regulatory accounting for
generation was discontinued in September 2000 which resulted in an after tax
extraordinary loss of $25 million.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,297,704 $960,837 $3,532,372 $2,522,474
---------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 42,702 50,452 132,100 139,781
Purchased Power 1,003,135 660,438 2,720,906 1,760,551
Other Operation 58,398 57,940 167,456 153,561
Maintenance 15,254 18,991 53,763 51,915
Depreciation and Amortization 32,352 25,091 95,213 74,531
Taxes Other Than Federal Income Taxes 36,473 31,079 101,289 93,640
Federal Income Taxes 32,470 33,284 69,899 70,011
------ ------ ------ ------
TOTAL OPERATING EXPENSES 1,220,784 877,275 3,340,626 2,343,990
--------- ------- --------- ---------
OPERATING INCOME 76,920 83,562 191,746 178,484
NONOPERATING INCOME (LOSS) 5,269 (683) 11,753 3,498
----- ---- ------ -----
INCOME BEFORE INTEREST CHARGES 82,189 82,879 203,499 181,982
INTEREST CHARGES 16,871 17,337 53,092 53,634
------ ------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 65,318 65,542 150,407 128,348
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION - net of tax (Note 2) - (25,236) (26,407) (25,236)
------ ------- ------- -------
NET INCOME 65,318 40,306 124,000 103,112
PREFERRED STOCK DIVIDEND REQUIREMENTS
244 416 847 1,481
--- --- --- -----
EARNINGS APPLICABLE TO
COMMON STOCK $ 65,074 $ 39,890 $ 123,153 $ 101,631
========== ==========AEP Affiliates 7,678 18,746
---------- ----------
TOTAL OPERATING REVENUES 949,315 1,125,573
---------- ----------
OPERATING EXPENSES:
Fuel 45,650 47,030
Purchased Power:
Electricity Marketing and Trading 637,921 799,639
AEP Affiliates 71,582 72,272
Other Operation 54,158 54,548
Maintenance 14,140 18,780
Depreciation and Amortization 32,736 31,482
Taxes Other Than Income Taxes 30,276 30,687
Income Taxes 17,304 23,020
---------- ----------
TOTAL OPERATING EXPENSES 903,767 1,077,458
---------- ----------
OPERATING INCOME 45,548 48,115
NONOPERATING INCOME 257,578 252,846
NONOPERATING EXPENSES 254,023 247,690
NONOPERATING INCOME TAX EXPENSE (CREDIT) 1,452 (2,133)
INTEREST CHARGES 13,793 17,733
---------- ----------
NET INCOME 33,858 37,671
PREFERRED STOCK DIVIDEND REQUIREMENTS 181 302
---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 33,677 $ 37,369
========== ==========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $115,243 $261,024 $ 99,069 $246,584
NET INCOME 65,318 40,306 124,000 103,112
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 20,738 169,650 62,214 216,950
Cumulative Preferred Stock 175 263 700 1,138
Capital Stock Expense 255 250 762 441
--- --- --- ---
BALANCE AT END OF PERIOD $159,393 $131,167 $159,393 $131,167
======== ========CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $176,103 $ 99,069
NET INCOME 33,858 37,671
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 21,766 20,738
Cumulative Preferred Stock 175 262
Capital Stock Expense 254 254
-------- --------
BALANCE AT END OF PERIOD $187,766 $115,486
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,576,522 $1,564,254$1,575,390 $1,574,506
Transmission 396,871 360,302402,391 401,405
Distribution 1,142,740 1,096,3651,167,184 1,159,105
General 146,720 156,534143,532 146,732
Construction Work in Progress 78,922 89,339
------ ------85,048 72,572
---------- ----------
Total Electric Utility Plant 3,341,775 3,266,7943,373,545 3,354,320
Accumulated Depreciation and Amortization 1,358,623 1,299,697
--------- ---------1,399,457 1,377,032
---------- ----------
NET ELECTRIC UTILITY PLANT 1,983,152 1,967,097
--------- ---------1,974,088 1,977,288
---------- ----------
OTHER PROPERTY AND INVESTMENTS 41,944 39,848
------ ------39,793 40,369
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 227,288 172,167
------- -------339,985 193,915
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 23,019 11,6006,497 12,358
Accounts Receivable:
Customers 52,491 73,71146,077 41,770
Affiliated Companies 77,952 49,59198,987 63,470
Miscellaneous 14,920 18,80719,325 16,968
Allowance for Uncollectible Accounts (659) (659)(719) (745)
Fuel - at average cost 22,137 13,12621,127 20,019
Materials and Supplies - at average cost 38,063 38,09734,240 38,984
Accrued Utility Revenues 4,509 9,63812,334 7,087
Energy Trading Contracts 562,351 1,085,989500,539 347,198
Prepayments and Other Current Assets 30,919 46,735
------ ------32,951 28,733
---------- ----------
TOTAL CURRENT ASSETS 825,702 1,346,635
------- ---------771,358 575,842
---------- ----------
REGULATORY ASSETS 266,273 291,553
------- -------258,725 262,267
---------- ----------
DEFERRED CHARGES 26,769 77,634
------ ------45,731 56,187
---------- ----------
TOTAL ASSETS $3,371,128 $3,894,934$3,429,680 $3,105,868
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(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 574,115 573,354574,622 574,369
Retained Earnings 159,393 99,069
------- ------187,766 176,103
---------- ----------
Total Common Shareowner's Equity 774,534 713,449803,414 791,498
Cumulative Preferred Stock - Subject to
Mandatory Redemption 10,000 15,00010,000
Long-term Debt 623,579 899,615
------- -------571,441 571,348
---------- ----------
TOTAL CAPITALIZATION 1,408,113 1,628,064
--------- ---------1,384,855 1,372,846
---------- ----------
OTHER NONCURRENT LIABILITIES 39,175 47,584
------ ------34,687 36,715
---------- ----------
CURRENT LIABILITIES:
Affiliated
Long-term Debt Due Within One Year 200,000 -220,500 220,500
Advances from Affiliates 140,154 88,732210,490 181,384
Accounts Payable - General 85,911 89,84653,925 62,393
Accounts Payable - Affiliated Companies 83,276 72,49399,514 83,697
Taxes Accrued 134,068 162,90496,417 116,364
Interest Accrued 15,845 13,36914,514 10,907
Energy Trading Contracts 529,145 1,115,967481,723 334,958
Other 45,437 60,701
------ ------33,421 34,600
---------- ----------
TOTAL CURRENT LIABILITIES 1,233,836 1,604,012
--------- ---------1,210,504 1,044,803
---------- ----------
DEFERRED INCOME TAXES 435,290 422,759
------- -------444,447 443,722
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 38,726 41,234
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 20,006 12,861
------ ------36,398 37,176
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 195,982 138,420
------- -------301,879 157,706
---------- ----------
DEFERRED CREDITS 16,910 12,900
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $3,371,128 $3,894,934$3,429,680 $3,105,868
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
(in thousands)
2002 2001
2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $124,000 $103,112$ 33,858 $ 37,671
Adjustments for Noncash Items:
Depreciation and Amortization 78,739 74,945
Amortization of Transition Assets 17,455 -32,786 31,638
Deferred Federal Income Taxes 23,527 7,945(313) 6,957
Deferred Investment Tax Credits (2,508) (2,541)
Amortization(778) (836)
Mark to Market of Deferred Property Taxes 53,168 50,130
Extraordinary Loss 26,407 25,236Energy Trading Contracts (5,849) (30,008)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (3,254) 3,511(42,207) (10,067)
Fuel, Materials and Supplies (8,977) 4073,636 (4,345)
Accrued Utility Revenues 5,129 40,080
Prepayments and Other Current Assets 15,816 (3,500)(5,247) 9,638
Accounts Payable 6,848 87,7067,349 17,605
Taxes Accrued (28,836) (35,879)(19,947) (38,504)
Interest Accrued 2,476 10,505
Energy Trading Contracts (net) (60,743) (8,619)3,607 11,122
Other (net) (40,658) (1,757)
------- ------Assets 992 12,798
Other Liabilities 3,505 (6,442)
--------- --------
Net Cash Flows From Operating Activities 208,589 351,281
------- -------11,392 37,227
--------- --------
INVESTING ACTIVITIES:
Construction Expenditures (110,631) (91,122)(24,807) (33,007)
Proceeds from Sale of Property 10,673 992
------ ---389 -
--------- --------
Net Cash Flows Used For Investing Activities (99,958) (90,130)(24,418) (33,007)
--------- -------- -------
FINANCING ACTIVITIES:
Proceeds from Issuance of Affiliated Long-term Debt 200,000 -
Change in Advances from Affiliates (net) 51,422 43,970
Change in Short-term Debt (net) - (45,500)
Retirement of Cumulative Preferred Stock (5,000) (10,000)
Retirement of Long-term Debt (280,632) (25,274)Money Pool 29,106 13,477
Dividends Paid on Common Stock (62,214) (216,950)(21,766) (20,738)
Dividends Paid on Cumulative Preferred Stock (788) (1,312)
---- ------(175) (262)
--------- --------
Net Cash Flows Used For Financing Activities (97,212) (255,066)
-------7,165 (7,523)
--------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 11,419 6,085(5,861) (3,303)
Cash and Cash Equivalents at Beginning of Period 12,358 11,600
5,107
------ -------------- --------
Cash and Cash Equivalents at End of Period $ 23,0196,497 $ 11,192
========8,297
========= Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $49,126,000========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $9,725,000 and $6,127,000
and for income taxes was $11,198,000 and $17,485,000 in 2002 and
$40,411,000 and for income taxes was $17,579,000 and $42,007,000 in 2001, and
2000, respectively. Noncash acquisitions under capital leases were $1,019,000
and $4,043,000 in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $84,000 in 2001.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists ofI&M is a public utility engaged in the generation, regulated retail power sales and wholesale power marketing and trading
of electricity; and energy delivery which consists ofpurchase, sale,
transmission and distribution services. We belongof electric power to 567,000 retail customers in
its service territory in northern and eastern Indiana and a portion of
southwestern Michigan. As a member of the AEP Power Pool, I&M shares the
revenues and the costs of the AEP Power Pool's wholesale sales to neighboring
utilities and power marketers including power trading transactions. I&M also
sells wholesale power to municipalities and electric cooperatives.
The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool members based on their relative peak demands and generating
reserves through the payment of capacity charges and the receipt of capacity
credits. AEP Power Pool members are also compensated for the out-of-pocket costs
of energy delivered to the AEP Power Pool and charged for energy received from
the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve
month peak demand relative to the total peak demand of all member companies as a
basis for sharing revenues and costs. The result of this calculation is each
company's member load ratio (MLR) which determines each company's percentage
share of revenues and costs.
I&M is committed under unit power agreements to purchase all of AEGCo's
50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other
utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. An
agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's
Rockport Plant capacity to KPCo through 2004. Therefore, I&M purchases 910 MW of
AEGCo's 50% share of Rockport Plant capacity.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a cost-based rate-regulated electric public utility
company, I&M's consolidated financial statements reflect the actions of
regulators that can result in the recognition of revenues and expenses in
different time periods than enterprises that are not rate regulated. In
accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of wholesale marketing andAEP's trading activities conducted on our behalf byare allocated to I&M as a member
of the AEP Power Pool. Net income increased $10 million inTrading activities involve the quarterpurchase and $145 million
insale of
energy under physical forward contracts at fixed and variable prices and the
year-to-date period primarily due to the return to servicebuying and selling of bothfinancial energy contracts which include exchange traded
futures and options and over-the-counter options and swaps. The majority of
I&M's Cook Plant nuclear units in June and December 2000.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $342 32 $1,173 42
Fuel Expense 3 6 36 24
Purchased Power Expense 360 51 1,073 56
Other Operation Expense (17) (12) (94) (22)
Maintenance Expense (22) (40) (73) (44)
Depreciation and Amortization 2 6 7 6
Taxes Other Than Federal Income Taxes 2 14 9 18
Federal Income Taxes 3 37 72 N.M.
Nonoperating Income 2 147 8 168
Interest Charges 1 2 5 7
N.M. = Not Meaningful
Operating revenues for the third quarter increased due to
increased wholesale sales while average wholesale prices declined. The
significant increase in operating revenues in the year-to-date period
resulted from increased wholesale volumes and prices. I&M's share of
the AEP System's sales to and forward trades with other utility systems
and power marketers and sales to the AEP Power Pool rose in 2001. The
number oftrading activities represent physical forward electricity contracts madethat are
typically settled by entering into offsetting physical contracts. Although
trading contracts are generally short-term, there are also long-term trading
contracts.
Accounting standards applicable to trading activities require that
changes in AEP System'sthe fair value of trading contracts be recognized in revenues prior
to settlement and is commonly referred to as mark-to-market (MTM) accounting.
Since I&M is a cost-based rate-regulated entity, changes in the fair value of
physical forward sale and purchase contracts in AEP's traditional marketing area
(upare deferred as regulatory liabilities (gains) or regulatory assets (losses).
The deferral reflects the fact that power sales and purchases are included in
regulated rates on a settlement basis. AEP's traditional marketing area is up to
two transmission systems from the AEP System's service territory) grewterritory. The change in the fair
value of physical forward sale and purchase contracts outside AEP's traditional
marketing area is included in nonoperating income on a net basis.
Mark-to-market accounting represents the change in the unrealized gain
or loss throughout the contract's term. When the contract actually settles, that
is, the energy is actually delivered in a sale or received in a purchase or the
parties agree to forego delivery and receipt of electricity and net settle in
cash, the unrealized gain or loss is reversed and the actual realized cash gain
or loss is recognized in the income statement. Therefore, as the contract's
market value changes over the contract's term an unrealized gain or loss is
deferred for contracts with delivery points in AEP's traditional marketing area
and for contracts with delivery points outside of AEP's traditional marketing
area the unrealized gain or loss is recognized as nonoperating income. When the
contract settles the total gain or loss is realized in cash and the impact on
the income statement depends on whether the contract's delivery points are
within or outside of AEP's traditional marketing area. For contracts with
delivery points in AEP's traditional marketing area, the total gain or loss
realized in cash is recognized in the income statement. Physical forward trading
sale contracts with delivery points in AEP's traditional marketing area are
included in revenues when the contracts settle. Physical forward trading
purchase contracts with delivery points in AEP's traditional marketing area are
included in purchased power expense when they settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are deferred as regulatory liabilities (gains)
or regulatory assets (losses). For contacts with delivery points outside of
AEP's traditional marketing area only the difference between the accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized in the income statement. Physical forward sales contracts for
delivery outside of AEP's traditional marketing area are included in
nonoperating income when the contract settles. Physical forward purchase
contracts for delivery outside of AEP's traditional marketing area are included
in nonoperating expenses when the contract settles. Prior to settlement, changes
in the fair value of physical forward sale and purchase contracts with delivery
points outside of AEP's traditional marketing area are included in nonoperating
income on a net basis. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading contract assets or liabilities as
appropriate.
Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior cumulative
unrealized net gain or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due. Liquidity risk represents the risk that imperfections in the market
will cause the price to be less or more than what the price should be based
purely on supply and demand. There are inherent risks related to the underlying
assumptions in models used to fair value open long-term trading contracts. AEP
has independent controls to evaluate the reasonableness of our valuation models.
However, energy markets, especially electricity markets, are imperfect and
volatile and unforeseen events can and will cause reasonable price curves to
differ from actual prices throughout a contract's term and when contracts
settle. Therefore, there could be significant adverse or favorable effects on
future results of operations and cash flows if market prices at settlement do
not correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing I&M to market risk. See "Quantitative and
Qualitative Disclosures about Market Risk" section for a discussion of the
policies and procedures used to manage exposure to risk from trading activities.
Results of Operations
Net income decreased $21 million or 66% due primarily to a reduction
in generation as a result of a refueling outage at one unit of I&M's Cook Plant,
maintenance outages at Rockport Plant and lower margins on electricity sales.
Operating revenues decreased 20% due to decreased wholesale marketing
and trading prices and the expansiondecline in generation due to power plant outages. The
following analyzes the changes in operating revenues:
Increase (Decrease)
(in millions) %
Electricity Marketing $(225.6) (20)
and Trading*
Energy Delivery* (3.4) (4)
Sales to AEP Affiliates (23.8) (33)
-------
Total $(252.8) (20)
=======
*Reflects the allocation of ourcertain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The decrease in electricity marketing and trading operation and increased liquidity in the markets. Changesrevenues was due to a
decline in wholesale prices reflect market conditions. Withreflecting soft demand caused by the returnslow economic
recovery and mild winter weather. Revenues from sales to serviceAEP affiliates declined
significantly reflecting less power being available for sale as one unit of the
nuclearCook Nuclear Plant was shutdown for refueling and both units in 2000, I&M's available generation increased resulting
in additional wholesale power salesof Rockport Plant
were scheduled for planned boiler maintenance. AEP Power Pool members are
compensated for the out-of-pocket costs of energy delivered to the AEP Power
Pool and charged for energy received from the AEP Power Pool. With the outages
in 2001.2002, I&M's available generation declined resulting in less power being
delivered to the AEP Power Pool.
Operating expenses declined 19% in 2002. The changes in the components
of operating expenses were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Fuel $ (9.8) (15)
Electricity Marketing and Trading
Purchases (216.2) (24)
Purchases from AEP Affiliates (10.0) (16)
Other Operation 14.4 15
Maintenance 2.9 10
Depreciation and Amortization 1.1 3
Taxes Other Than Income Taxes - -
Income Taxes (12.8) (68)
-------
Total $(230.4) (19)
=======
Fuel expense increased primarily due to increased generation
reflecting the return to service of the nuclear units following the
extended outage.
The increase in purchased power expense resulted mainly from
increases in wholesale prices and sales and trading volume in the
year-to-date period. During the third quarter, a decline in average
prices, reflecting market conditions, partly offset the volume increase.
Other operation and maintenance expenses decreased primarily due to the cessation of expenses relateddecline in generation
reflecting the plant outages, mild winter weather and a slow economic recovery.
The decrease in electricity marketing and trading purchases resulted
mainly from the decrease in energy prices.
Purchases from AEP affiliates declined due to work for the 2000 restart ofRockport Plant outages
as I&M is required to purchase AEGCo's Rockport Plant generation under their
unit power agreement.
Other operation expense increased due to higher costs resulting from the
Cook Plant units.generating plants outages, property insurance and employee benefit costs.
The increase in depreciation and amortization charges reflects
increased generation and distribution plant investments and amortization
of deferred merger costs.
Taxes other than federal income taxes and federal incomemaintenance expense is primarily due to costs related to
the outages.
Income tax expense attributable to operations increaseddecreased significantly
due primarily due to increasesa decline in pre-tax operating income.
The increasedecrease in nonoperating income reflects an increase in net
gains from trading transactionsand nonoperating expenses is due to
lower prices for power sold and purchased outside the AEP System'sof AEP's traditional marketing
area and speculative financial transactions (options, futures
and swaps).reflecting reduced demand.
The decrease in nonoperating income tax expense reflects a decline in
pre-tax nonoperating income.
Interest charges increaseddecreased due to a decline in short-term rates and
lower amounts of interest
being capitalized as part of plant construction costs.outstanding borrowings.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,402,178 $1,060,654 $3,953,590 $2,780,510
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 59,535 56,338 183,999 148,042
Purchased Power 1,070,889 710,605 2,978,930 1,905,531
Other Operation 122,809 139,375 330,369 424,254
Maintenance 31,913 53,596 91,594 164,821
Depreciation and Amortization 41,172 38,951 122,735 115,661
Taxes Other Than Federal Income Taxes 19,574 17,156 60,222 51,152
Federal Income Tax Expense (Credit) 11,777 8,577 41,194 (31,157)
------ ----- ------ -------
TOTAL OPERATING EXPENSES 1,357,669 1,024,598 3,809,043 2,778,304
--------- --------- --------- ---------
OPERATING INCOME 44,509 36,056 144,547 2,206
NONOPERATING INCOME 3,320 1,344 12,176 4,546
----- ----- ------ -----
INCOME BEFORE INTEREST CHARGES 47,829 37,400 156,723 6,752
INTEREST CHARGES 22,765 22,210 71,922 67,296
------ ------ ------ ------
NET INCOME (LOSS) 25,064 15,190 84,801 (60,544)
PREFERRED STOCK DIVIDENDREQUIREMENTS
1,155 1,156 3,466 3,469
----- ----- ----- -----
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK
$ 23,909 $ 14,034 $ 81,335 $ (64,013)
========== ========INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $ 917,013 $1,142,617
Energy Delivery 74,537 77,937
Sales to AEP Affiliates 47,209 70,984
---------- ----------
TOTAL OPERATING REVENUES 1,038,759 1,291,538
---------- ----------
OPERATING EXPENSES:
Fuel 54,156 63,973
Purchased Power:
Electricity Marketing and Trading 691,806 908,039
AEP Affiliates 53,507 63,548
Other Operation 111,766 97,363
Maintenance 31,043 28,175
Depreciation and Amortization 41,866 40,723
Taxes Other Than Income Taxes 18,241 18,238
Income Taxes 6,011 18,781
---------- ----------
TOTAL OPERATING EXPENSES 1,008,396 1,238,840
---------- ----------
OPERATING INCOME 30,363 52,698
NONOPERATING INCOME 295,185 302,274
NONOPERATING EXPENSES 291,491 295,714
NONOPERATING INCOME TAX EXPENSE (CREDIT) (425) 2,115
INTEREST CHARGES 23,424 24,780
---------- ----------
NET INCOME 11,058 32,363
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,155 1,155
---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 9,903 $ 31,208
========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME (LOSS) $25,064 $15,190 $84,801 $(60,544)
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (878) - (3,700) -
---- ------ ------ ------
COMPREHENSIVE INCOME (LOSS) $24,186 $15,190 $81,101 $(60,544)CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
NET INCOME $11,058 $32,363
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge 1,259 (1,919)
------- -------
COMPREHENSIVE INCOME $12,317 $30,444
======= ======= ======= ========
The common stock of I&M is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $60,869 $60,930 $ 3,443 $166,389
NET INCOME (LOSS) 25,064 15,190 84,801 (60,544)
DEDUCTIONS:
Cash Dividends Declared:
Common Stock - - - 26,290
Cumulative Preferred Stock 1,121 - 3,365 3,368
Capital Stock Expense 34 34 101 101
-- -- --- ---
BALANCE AT END OF PERIOD $84,778 $76,086 $84,778 $ 76,086INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $74,605 $ 3,443
NET INCOME 11,058 32,363
DEDUCTIONS:
Cash Dividends Declared -
Cumulative Preferred Stock 1,122 1,122
Capital Stock Expense 33 33
------- -------
BALANCE AT END OF PERIOD $84,508 $34,651
======= ======= ======= ========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,751,287 $2,708,436$2,759,924 $2,758,160
Transmission 953,699 945,709957,905 957,336
Distribution 888,851 863,736899,146 900,921
General (including nuclear fuel) 216,682 257,152220,140 233,005
Construction Work in Progress 83,809 96,440
------ ------91,819 74,299
---------- ----------
Total Electric Utility Plant 4,894,328 4,871,4734,928,934 4,923,721
Accumulated Depreciation and Amortization 2,402,447 2,280,521
--------- ---------2,469,854 2,436,972
---------- ----------
NET ELECTRIC UTILITY PLANT 2,491,881 2,590,952
--------- ---------2,459,080 2,486,749
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS 816,169 778,720
------- -------844,616 834,109
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 253,571 194,947
------- -------385,768 215,544
---------- ----------
OTHER PROPERTY AND INVESTMENTS 130,955 131,417
------- -------124,762 127,977
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 27,398 14,83510,849 16,804
Advances to Affiliates 37,422 46,309
Accounts Receivable:
Customers 69,668 106,83266,101 60,864
Affiliated Companies 47,711 48,70671,244 31,908
Miscellaneous 30,717 27,49139,204 25,398
Allowance for Uncollectible Accounts (734) (759)(804) (741)
Fuel - at average cost 27,926 16,53228,264 28,989
Materials and Supplies - at average cost 89,493 84,47186,643 91,440
Energy Trading Contracts 637,645 1,230,041579,967 399,195
Accrued Utility Revenues 5,405 2,072
Prepayments 7,450 6,066
----- -----9,838 6,497
---------- ----------
TOTAL CURRENT ASSETS 937,274 1,534,215
------- ---------934,133 708,735
---------- ----------
REGULATORY ASSETS 466,752 552,140
------- -------414,045 408,927
---------- ----------
DEFERRED CHARGES 24,298 36,156
------ ------40,943 34,967
---------- ----------
TOTAL ASSETS $5,120,900 $5,818,547$5,203,347 $4,817,008
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(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 733,173 733,072733,249 733,216
Accumulated Other Comprehensive Income (Loss) (3,700) -(2,576) (3,835)
Retained Earnings 84,778 3,443
------ -----84,508 74,605
---------- ----------
Total Common Shareowner's Equity 870,835 793,099871,765 860,570
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,736 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,152,513 1,298,939
--------- ---------1,313,389 1,312,082
---------- ----------
TOTAL CAPITALIZATION 2,097,029 2,165,719
--------- ---------2,258,835 2,246,333
---------- ----------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 587,398 560,628605,988 600,244
Other 96,523 108,600
------ -------86,872 87,025
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES 683,921 669,228
------- -------692,860 687,269
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 200,000 90,000
Advances from Affiliates 214,420 253,582340,000 340,000
Accounts Payable:
General 87,769 119,47277,745 90,817
Affiliated Companies 45,670 75,48646,249 43,956
Taxes Accrued 116,196 68,41691,152 69,761
Interest Accrued 24,001 21,639
Rent Accrued - Rockport Plant Unit 2 23,427 4,96328,265 20,691
Obligations Under Capital Leases 9,796 100,8489,483 10,840
Energy Trading Contracts 591,679 1,275,097554,916 383,714
Other 79,827 92,107
------ ------88,790 72,435
---------- ----------
TOTAL CURRENT LIABILITIES 1,392,785 2,101,610
--------- ---------1,236,600 1,032,214
---------- ----------
DEFERRED INCOME TAXES 465,565 487,945
------- -------389,177 400,531
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 108,169 113,773
------- -------103,604 105,449
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 78,519 81,299
------ ------76,665 77,592
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 214,683 156,736
------- -------347,151 175,581
---------- ----------
DEFERRED CREDITS 80,229 42,237
------ ------98,455 92,039
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,120,900 $5,818,547$5,203,347 $4,817,008
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $ 84,80111,058 $ (60,544)32,363
Adjustments for Noncash Items:
Depreciation and Amortization 124,993 122,34542,184 41,589
Amortization (Deferral) of Incremental
Nuclear Refueling Outage Expenses (net) (224) 4,830(24,130) 316
Unrecovered Fuel and Purchased Power Costs 28,126 28,1269,375 9,375
Amortization of Nuclear Outage Costs 30,000 30,00010,000 10,000
Deferred Federal Income Taxes (6,517) (25,619)(7,132) (2,462)
Deferred Investment Tax Credits (5,604) (5,660)(1,845) (1,868)
Mark-to-Market of Energy Trading Contracts (3,708) (17,447)
Deferred Property Taxes (8,409) (9,731)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 34,908 23,303(58,316) 43,803
Fuel, Materials and Supplies (16,416) (6,304)5,522 (6,098)
Accrued Utility Revenues (3,333) - 44,428
Accounts Payable (61,519) 47,236(10,779) (21,638)
Taxes Accrued 47,780 (48,970)21,391 28,166
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Net Change in Energy Trading Contracts (91,699) (4,039)
Regulatory Liability - Trading Gains 39,040 (10,143)
Other (net) 31,283 (29,211)
------ -------Assets 8,328 (735)
Change in Other Liabilities 4,008 (17,909)
--------- ---------
Net Cash Flows From Operating Activities 257,416 128,242
------- -------12,678 106,188
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (65,312) (129,799)(26,398) (18,241)
Buyout of Nuclear Fuel Leases - (92,616)
-
Other 524 587
--- ------------ ---------
Net Cash Flows Used For Investing Activities (157,404) (129,212)
-------- --------(26,398) (110,857)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 199,220
Retirement of Long-term Debt (44,922) (48,000)
Retirement of Cumulative Preferred Stock - (314)
Change in Short-term Debt (net) - (224,262)
Change in Advances from Affiliates (net) (39,162) 113,423
Dividends Paid on Common Stock - (26,290)8,887 4,878
Dividends Paid on Cumulative Preferred Stock (3,365) (3,368)
------ ------(1,122) (1,122)
--------- ---------
Net Cash Flows From (Used For) Financing Activities (87,449) 10,409
------- ------7,765 3,756
--------- ---------
Net IncreaseDecrease in Cash and Cash Equivalents 12,563 9,439(5,955) (913)
Cash and Cash Equivalents at Beginning of Period 16,804 14,835
3,863
------ -------------- ---------
Cash and Cash Equivalents at End of Period $ 27,39810,849 $ 13,302
=========13,922
========= Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $67,657,000=========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $15,090,000 and
$21,610,000 and for income taxes was $(470,000) and $7,471,000 in 2002 and
$57,466,000 and for income taxes was $13,079,000 and $43,675,000 in 2001, and
2000, respectively. Noncash acquisitions under capital leases were $1,023,000
and $19,134,000 in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $991,000 in 2001.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale, which consists ofKPCo is a public utility engaged in the generation, regulated retail power sales and wholesale power marketing and trading of
electricity; and energy delivery, which consists ofpurchase, sale,
transmission and distribution services. We belongof electric power serving 172,000 retail customers
in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the
revenues and costs of the AEP Power Pool's wholesale sales to neighboring
utility systems and power marketers including power trading transactions. KPCo
also sells wholesale power to municipalities.
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. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a cost-based rate-regulated electric public utility
company, KPCo's financial statements reflect the actions of regulators that can
result in the recognition of revenues and expenses in different time periods
than enterprises that are not rate regulated. In accordance with SFAS 71,
regulatory assets (deferred expenses) and regulatory liabilities (future revenue
reductions or refunds) are recorded to reflect the economic effects of
regulation by matching expenses with their recovery through regulated revenues
in the same accounting period.
When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of wholesale marketing andAEP's trading activities conducted on our behalf
byare allocated to KPCO as a member
of the AEP Power Pool. NetTrading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and the
buying and selling of financial energy contracts which include exchange traded
futures and options and over-the-counter options and swaps. The majority of
trading activities represent physical forward electricity contracts that are
typically settled by entering into offsetting physical contracts. Although
trading contracts are generally short-term, there are also long-term trading
contracts.
Accounting standards applicable to trading activities require that
changes in the fair value of trading contacts be recognized in revenues prior to
settlement and is commonly referred to as mark-to-market (MTM) accounting. Since
KPCO is a cost-based rate-regulated entity, changes in the fair value of
physical forward sale and purchase contracts in AEP's traditional marketing area
are deferred as regulatory liabilities (gains) or regulatory assets (losses).
AEP's traditional marketing area is up to two transmission systems from the AEP
Service territory. The change in the fair value of physical forward sale and
purchase contracts outside AEP's traditional marketing area is included in
nonoperating income decreased $1.4on a net basis.
Mark-to-market accounting represents the change in the unrealized gain
or loss throughout the contract's term. When the contract actually settles, that
is, the energy is actually delivered in a sale or received in a purchase or the
parties agree to forego delivery and receipt of electricity and net settle in
cash, the unrealized gain or loss is reversed and the actual realized cash gain
or loss is recognized in the income statement. Therefore, as the contract's
market value changes over the contract's term an unrealized gain or loss is
deferred for contracts with delivery points in AEP's traditional marketing area
and for contracts with delivery points outside of AEP's traditional marketing
area the unrealized gain or loss is recognized as nonoperating income. When the
contract settles the total gain or loss is realized in cash and the impact on
the income statement depends on whether the contract's delivery points are
within or outside of AEP's traditional marketing area. For contracts with
delivery points in AEP's traditional marketing area, the total gain or loss
realized in cash is recognized in the income statement. Physical forward trading
sale contracts with delivery points in AEP's traditional marketing area are
included in revenues when the contracts settle. Physical forward trading
purchase contracts with delivery points in AEP's traditional marketing area are
included in purchased power expense when they settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are deferred as regulatory liabilities (gains)
or regulatory assets (losses). For contacts with delivery points outside of
AEP's traditional marketing area only the difference between the accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized in the income statement. Physical forward sales contracts for
delivery outside of AEP's traditional marketing area are included in
nonoperating income when the contract settles. Physical forward purchase
contracts for delivery outside of AEP's traditional marketing area are included
in nonoperating expenses when the contract settles. Prior to settlement, changes
in the fair value of physical forward sale and purchase contracts with delivery
points outside of AEP's traditional marketing area are included in nonoperating
income on a net basis. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading assets or liabilities.
Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the cumulative prior
unrealized net gain or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due. Liquidity risk represents the risk that imperfections in the market
will cause the price to be less than or more than what the price should be based
purely on supply and demand. There are inherent risks related to the underlying
assumptions in models used to fair value open long-term trading contracts. AEP
has independent controls to evaluate the reasonableness of our valuation models.
However, energy markets, especially electricity markets, are imperfect and
volatile and unforeseen events can and will cause reasonable price curves to
differ from actual prices throughout a contract's term and when contracts
settle. Therefore, there could be significant adverse or favorable effects on
future results of operations and cash flows if market prices at settlement do
not correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing KPCO to market risk. See "Quantitative and
Qualitative Disclosures About Market Risk" section for a discussion of the
policies and procedures used to manage exposure to risk from trading activities.
Results of Operations
Decreases in revenues were offset by sharper decreases in operating
expenses which resulted in an increase in net income of $3 million or 21% for45%.
The following analyzes the quarterchanges in operating revenues:
Increase (Decrease)
(in millions) %
Electricity Marketing
And Trading* $(103) (25)
Energy Delivery* (1) (3)
Sales to AEP Affiliates (4) (38)
-----
Total $(108) (23)
=====
*Reflects the allocation of certain transmission and $2.1
million or 12% year-to-datedistribution
revenues included in bundled retail rates to energy delivery.
The decrease in revenues is due primarily to a declinedecrease in operating income. This decline
was primarily attributable toelectricity
trading prices and mild winter weather. In the first quarter of 2002 the AEP
Power Pool grew its electric trading business resulting in a slowing economy and reduced wholesale energy
margins. Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $126.5 35 $450.7 48
Fuel Expense (5.8) (25) (5.0) (9)
Purchased Power Expense 131.9 46 456.3 62
Other Operation Expense 1.3 9 8.0 22
Maintenance Expense (0.1) (2) (4.3) (21)
Depreciation and Amortization Expense 0.3 4 1.2 5
Taxes Other Than Federal Income Taxes 0.4 17 1.8 22
Federal Income Taxes (0.4) (11) (1.9) (23)
Nonoperating Income (0.6) (234) 1.5 176
Interest Charges (0.3) (4) (1.6) (7)
Increasessignificant
increase in operating revenues are a result of increases in power
trading activity. Revenues from sales to and forward trades with other utility
systems and power marketers rose by 50% and 69% for the quarter and year-to-date
periods, respectively. The number of forward electricity contracts grewentered into AEP's
traditional marketing area (up to two transmission systems from AEP's service
territory). This growth in volume was offset by reduced demand which lowered
selling prices and margins. Depressed prices were experienced in both trading
and wholesale sales, resulting in an overall decrease in revenues due to mild
weather and a slow recovery from the expansioneconomic recession. Retail activity for the
period was comparable to that of trading operations and increased liquiditythe same period last year.
Changes in the markets. A
downward trendcomponents of operating expenses were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Fuel $ 4 21
Electricity Marketing and
Trading Purchases (106) (30)
Purchases from AEP Affiliates (7) (19)
Other Operation (2) (15)
Maintenance (1) (16)
-----
Total $(112) (25)
=====
Fuel expense increased due to difficulties experienced by one of the
Company's main coal suppliers forcing KPCo to go to the open market to address
shortfalls in wholesalesupply at higher prices reflected market conditions.
Fuelin the coal spot market. Management is
exploring opportunities for alternative suppliers and contracted rates.
Purchased power expense decreases were primarily attributable to lower
prices resulting from mild winter weather and declining demand for electricity.
Other operation expense decreased due to a decrease in trading incentive
cost accruals.
Maintenance expense decreased as a result of credits from profits on trading
power. Under the Kentucky commission's fuel clause mechanism, a portion of the
profits on wholesale transactions are shared with the customers. This sharing is
recognized through creditsadjustments to fuel expense thus reducing overall fuel expense.
Purchased power expense for the wholesale business increased due to
additional purchases tolabor force
and contractor support, the increased sales and trading volume.
Increases in other operation expense for the quarter were a result of
increased trading incentive compensation expense and charges relatedlatter being converted to severance pay for distribution employees. Increases in year-to-date other
operation expense are primarily attributable to trader compensation expenses and
decreases in AEP transmission equalization credits. Under the AEP East Region
Transmission Agreement, KPCo and certain affiliates share the costs associated
with the ownership of their transmission system based upon each company's peak
demand and investment. An increase in KPCo's peak demand relative to its
affiliates' peak demand was the main reason for the decline in the transmission
equalization credits. Other changes contributing to increases in other operation
expense include an increase in medical insurance rates, and increases in
accounts receivable factoring costs stemming from nine months activity in 2001"as needed" versus three months in 2000 when the program was implemented.
Lower maintenance expense is a result of significant planned maintenance
outages incurred at the Big Sandy Plant in year 2000 for which there is no
comparable activity in the current year.
Depreciation and amortization expense increased as a result of additions
to property, plant and equipment and the resultant increase in the depreciablefull
time basis.
Federal income tax on operations decreased due to a decline in pre-tax
income.
The quarter to date decrease in nonoperating income and expenses was due to losses
resulting froma decrease
in power trading activity. The quarterly decrease is mitigated by
year-to-date net gains forrevenues and purchases from non-regulated AEP Power Pool
trading transactions outside of the AEP System's traditional marketing area. As
with power trading activity and otherwithin the traditional marketing areas,
non-regulated financial
market investments.
Interest charges declinedtrading transactions also experienced declining prices due to
lower outstanding debt balancesreduced demand and lower interest rates in 2001.mild weather.
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $485,820 $359,296 $1,384,108 $933,410
-------- -------- ---------- --------
OPERATING EXPENSES:
Fuel 17,581 23,366 52,955 58,039
Purchased Power 420,402 288,479 1,196,180 739,864
Other Operation 15,430 14,117 44,628 36,604
Maintenance 5,984 6,098 16,598 20,903
Depreciation and Amortization 8,163 7,828 24,270 23,107
Taxes Other Than Federal Income Taxes 2,802 2,387 9,638 7,880
Federal Income Taxes 2,871 3,231 6,284 8,210
----- ----- ----- -----
TOTAL OPERATING EXPENSES 473,233 345,506 1,350,553 894,607
------- ------- --------- -------
OPERATING INCOME 12,587 13,790 33,555 38,803
NONOPERATING INCOME (LOSS) (326) 243 2,392 868
---- --- ----- ---
INCOME BEFORE INTEREST CHARGES 12,261 14,033 35,947 39,671
INTEREST CHARGES 6,949 7,272 20,818 22,409
----- ----- ------ ------
NET INCOME $ 5,312 $ 6,761 $ 15,129 $ 17,262
======== ========KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES:
Electric Marketing and Trading $310,157 $413,133
Energy Delivery 35,129 36,327
Sales to AEP Affiliates 6,022 9,697
-------- --------
TOTAL OPERATING REVENUES 351,308 459,157
-------- --------
OPERATING EXPENSES:
Fuel 21,767 17,956
Purchased Power
Electricity Marketing and Trading 252,005 358,230
AEP Affiliates 28,941 35,635
Other Operation 12,469 14,728
Maintenance 4,549 5,429
Depreciation and Amortization 8,257 8,027
Taxes Other Than Income Taxes 2,135 2,049
Income Taxes 5,701 5,834
-------- --------
TOTAL OPERATING EXPENSES 335,824 447,888
-------- --------
OPERATING INCOME 15,484 11,269
NONOPERATING INCOME 101,984 113,516
NONOPERATING EXPENSES 100,912 111,273
NONOPERATING INCOME TAX CREDIT 190 567
INTEREST CHARGES 6,500 7,004
-------- --------
NET INCOME $ 10,246 $ 7,075
======== ========
STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME $5,312 $6,761 $15,129 $17,262
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (618) - (2,040) -
---- ------- ------ -------
COMPREHENSIVE INCOME $4,694 $6,761 $13,089 $17,262
====== ====== ======= =======
The common stock of KPCoSTATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
NET INCOME $10,246 $ 7,075
STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge 516 (1,354)
------- -------
COMPREHENSIVE INCOME $10,762 $ 5,721
======= =======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $52,208 $62,431 $57,513 $67,110
NET INCOME 5,312 6,761 15,129 17,262
CASH DIVIDENDS DECLARED:
Common Stock 7,561 7,590 22,683 22,770
----- ----- ------ ------
BALANCE AT END OF PERIOD $49,959 $61,602 $49,959 $61,602
======= =======KENTUCKY POWER COMPANY
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $48,833 $57,513
NET INCOME 10,246 7,075
CASH DIVIDENDS DECLARED:
Common Stock 7,044 7,561
------- -------
BALANCE AT END OF PERIOD $52,035 $57,027
======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 270,996271,096 $ 271,107271,070
Transmission 370,373 360,563371,924 374,116
Distribution 398,792 387,499401,798 402,537
General 65,021 67,47664,815 65,059
Construction Work in Progress 15,059 16,41931,852 15,633
------ ----------------
Total Electric Utility Plant 1,120,241 1,103,0641,141,485 1,128,415
Accumulated Depreciation and Amortization 377,938 360,648389,694 384,104
------- -------
NET ELECTRIC UTILITY PLANT 742,303 742,416751,791 744,311
------- -------
OTHER PROPERTY AND INVESTMENTS 6,894 6,5596,472 6,492
----- -----
LONG-TERM ENERGY TRADING CONTRACTS 92,242 76,657
------134,272 77,972
------- ------
CURRENT ASSETS:
Cash and Cash Equivalents 7,909 2,270417 1,947
Accounts Receivable:
Customers 21,684 34,55520,762 20,036
Affiliated Companies 22,008 22,11929,249 16,012
Miscellaneous 4,119 6,4193,937 3,333
Allowance for Uncollectible Accounts (278) (282)(233) (264)
Fuel - at average cost 7,521 4,76014,026 12,060
Materials and Supplies - at average cost 15,898 15,40815,559 15,766
Accrued Utility Revenues 2,215 6,5008,316 5,395
Energy Trading Contracts 226,116 483,537198,129 139,605
Prepayments and Other 1,047 766383 1,314
--- ----- ---
TOTAL CURRENT ASSETS 308,239 576,052290,545 215,204
------- -------
REGULATORY ASSETS 97,757 98,51598,822 97,692
------ ------
DEFERRED CHARGES 9,816 11,817
-----10,334 11,572
------ ------
TOTAL ASSETS $1,257,251 $1,512,016$1,292,236 $1,153,243
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------2001
-------------- -----------------
(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 158,750 158,750
Accumulated Other Comprehensive Income (Loss) (2,040) -(1,387) (1,903)
Retained Earnings 49,959 57,51352,035 48,833
------ ------
Total Common Shareowner's Equity 257,119 266,713259,848 256,130
Long-term Debt 246,041 270,880
Long-term Debt - Affiliated Company 75,000 -
------ -236,646 251,093
------- -------
TOTAL CAPITALIZATION 578,160 537,593496,494 507,223
------- -------
OTHER NONCURRENT LIABILITIES 13,075 18,34811,670 11,929
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 25,000 60,000109,500 95,000
Advances from Affiliates 64,246 47,63676,794 66,200
Accounts Payable:
General 31,438 32,04320,428 24,050
Affiliated Companies 23,673 37,50631,797 22,557
Customer Deposits 5,290 4,3896,260 4,461
Taxes Accrued 7,402 11,88512,015 10,305
Interest Accrued 6,873 5,6105,363 5,269
Energy Trading Contracts 216,755 496,884199,434 144,364
Other 17,514 14,51711,784 12,296
------ ------
TOTAL CURRENT LIABILITIES 398,191 710,470473,375 384,502
------- -------
DEFERRED INCOME TAXES 174,639 165,935168,086 168,304
------- -------
DEFERRED INVESTMENT TAX CREDITS 10,767 11,65610,110 10,405
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 78,802 61,632
------119,222 63,412
------- ------
DEFERRED CREDITS 3,617 6,382
-----13,279 7,468
------ -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,257,251 $1,512,016$1,292,236 $1,153,243
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 15,129 $ 17,26210,246 $7,075
Adjustments for Noncash Items:
Depreciation and Amortization 24,270 23,1128,257 8,029
Deferred Federal Income Taxes 9,644 4,081(556) 4,194
Deferred Investment Tax Credits (889) (894)
Amortization of Deferred Property Taxes 4,299 4,157(295) (297)
Deferred Fuel Costs (net) (2,708) 4,4301,542 (1,271)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 15,278 (8,128)(14,598) 10,227
Fuel, Materials and Supplies (3,251) 5,718(1,759) (350)
Accrued Utility Revenues 4,285 13,737(2,921) 3,243
Accounts Payable (14,438) 32,7635,618 3,177
Taxes Accrued (4,483) (1,323)
Net1,710 (3,691)
Mark to Market Energy Contracts (1,858) (5,976)
Change in Energy Trading Contracts (21,123) (2,171)
Other (net) (2,889) (5,069)
------ ------Assets 4,997 (10,086)
Change in Other Liabilities 435 5,871
--- -----
Net Cash Flows From Operating Activities 23,124 87,67510,818 20,145
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (26,628) (23,765)(15,898) (5,746)
Proceeds from Sales of Property - 216
----- --- -----
Net Cash Flow Used for Investing Activities (26,412) (23,765)(15,898) (5,530)
------- -------------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - Affiliated Company 75,000 -
Retirement of Long-term Debt (60,000) (25,000)
Change in Short-term Debt (net) - (39,665)
Change in Advances from Affiliates (net) 16,610 23,86310,594 (8,033)
Dividends Paid (22,683) (22,770)
------- -------(7,044) (7,561)
------ ------
Net Cash Flows From (Used For) Financing Activities 8,927 (63,572)3,550 (15,594)
----- -------
Net IncreaseDecrease in Cash and Cash Equivalents 5,639 338(1,530) (979)
Cash and Cash Equivalents at Beginning of Period 1,947 2,270
674
----- --------
Cash and Cash Equivalents at End of Period $ 7,909 $ 1,012
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $18,899,000417 $1,291
===== ======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $6,328,000 and $4,529,000
and for income taxes was $3,053,000 and $4,354,000 in 2002 and 2001,
respectively. Noncash acquisitions under capital leases were $22,000 and
$661,000 in 2002 and
$19,776,000 and for income taxes was $6,011,000 and $5,167,000 in 2001, and 2000,
respectively. Noncash acquisitions under capital leases were $817,000 and
$2,440,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists ofOPCo is a public utility engaged in the generation, marketing and trading of electricity; and energy delivery which consists ofsale, purchase,
transmission and distribution services. We belongof electric power to approximately 698,000
customers in the northwestern, east central, eastern and southern sections of
Ohio. As a member of the AEP Power Pool, OPCo shares the revenues and the costs
of the AEP Power Pool's wholesale sales to neighboring utilities and power
marketers including power trading transactions. OPCo also sells wholesale power
to municipalities and electric cooperatives.
The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool members based on their relative peak demands and generating
reserves through the payment of capacity charges and the receipt of capacity
credits. AEP Power Pool members are also compensated for the out-of-pocket costs
of energy delivered to the AEP Power Pool and charged for energy received from
the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve
month peak demand relative to the total peak demand of all member companies as a
basis for sharing revenues and costs. The result of this calculation is each
company's member load ratio (MLR) which determines each company's percentage
share of revenues and costs.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of wholesale marketing andAEP's trading activities conducted on our behalf byare allocated to OPCo as a member
of the AEP Power Pool. Net income decreased $7 millionTrading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and the
buying and selling of financial energy contracts which include exchange traded
futures and options and over-the-counter options and swaps. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of open energy trading contracts.
Recording the net change in the fair value of open trading contracts
prior to settlement is commonly referred to as mark-to-market (MTM) accounting.
Under MTM accounting the change in the unrealized gain or 12%loss throughout a
contract's term is recognized in each accounting period. When the contract
actually settles, that is, the energy is actually delivered in a sale or
received in a purchase or the parties agree to forego delivery and receipt and
net settle in cash, the unrealized gain or loss is reversed and the actual
realized cash gain or loss is recognized. Therefore, over the trading contract's
term an unrealized gain or loss is recognized as the contract's market value
changes. When the contract settles the total gain or loss is realized in cash
but only the difference between the accumulated unrealized net gains or losses
recorded in prior months and the cash proceeds is recognized. Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities.
The majority of our trading activities represent physical forward
electricity contracts that are typically settled by entering into offsetting
contracts. An example of our trading activities is when, in January, we enter
into a forward sales contract to deliver electricity in July. At the end of each
month until the contract settles in July, we would record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of a gain
or loss in cash and reverse the previously recorded cumulative unrealized gain
or loss.
Depending on whether the delivery point for the third quarter of 2001
and $47 million or 29% for the year-to-date period. We recorded extraordinary
losses in the second quarter of 2001 and third quarter of 2000 for the effects
of deregulation. Income before extraordinary item decreased by $26 million or
33% for the quarter and $45 million or 25% in the year-to-date period. A decline
in wholesale business performance and the implementation of customer choice
account for the reduction in the quarter's earnings. In connection with the
start of customer choice on January 1, 2001, the generation portion of
residential rates was reduced by 5% and the amortization of transition
regulatory assets began. Although performance of our wholesale businesselectricity is up
for the year-to-date period, the implementation of customer choice caused
earnings to decline year-to-date.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $335 23 $1,178 30
Fuel Expense (22) (11) (34) (6)
Purchased Power Expense 364 38 1,209 50
Other Operation 4 4 18 7
Maintenance Expense 6 20 16 18
Depreciation and Amortization 20 51 61 52
Taxes Other Than Federal Income Taxes 10 24 12 10
Federal Income Taxes (20) (47) (44) (39)
Nonoperating Income 4 165 19 283
Interest Charges 3 13 3 5
Extraordinary Loss (19) N.M. 3 14
N.M. = Not Meaningful
The significant increase in revenues for the quarter is due to a 63%
increase in trading volume partially offset by lower wholesale electricity
prices. The significant year-to-date revenue increase is due to a 31% increase
in trading volume and an increase in wholesale electricity prices due to changes
in market conditions. Expansion of the wholesale business' trading operation and
greater liquidity in the marketplace resulted in an increase in the number of
forward electricity purchase and sales contracts made in
AEP's traditional marketing area (upor not determines where the contract is
reported on OPCo's income statement. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory. Physical forward
trading sale contracts with delivery points in AEP's service territory).
Fuel expense decreased during both periods due to decreased generation
and a lower average unit cost of fuel.
Fortraditional marketing area
are included in revenues when the quarter the increasecontracts settle. Physical forward trading
purchase contracts with delivery points in AEP's traditional marketing area are
included in purchased power expense was attributablewhen they settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are included in revenues on a net basis.
Physical forward sales contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating income when the contract settles.
Physical forward purchase contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating expenses when the contract settles.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of AEP's traditional marketing
area are included in nonoperating income on a net basis.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts from this point forward will have no further impact on
results of operations but will have an offsetting and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase contract prior to entering into a sales contract. If
the sale and purchase contracts do not match exactly as to volumes, delivery
point, schedule and other key terms, then there could be continuing
mark-to-market effects on results of operations from recording additional
changes in fair values using mark-to-market accounting.
Trading of electricity options, futures and swaps represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior cumulative
unrealized net gain or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices at
settlement do not correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing OPCo to market risk. See "Quantitative and
Qualitative Disclosures about Market Risk" section for a discussion of the
policies and procedures used to manage exposure to risk from trading activities.
Results of Operations
Net income increased $10.7 million or 20%. While revenues declined
$316.1 million, operating expenses declined even more resulting in an increase
in net income. Margins increased in 2002 for electricity sales to retail
customers, reflecting the spread between capped or frozen retail rates and weak
wholesale business' electric trading volume offsetenergy prices and cost of fuel. Weak wholesale prices, that benefited
our retail sales, resulted in part by a decreaselower margins reducing earnings from wholesale
energy marketing and trading.
The following analyzes the changes in wholesale electricity prices. Foroperating revenues:
Increase (Decrease)
(in millions) %
Electricity Marketing $(294.6) (21)
and Trading*
Energy Delivery* 9.9 8
Sales to AEP Affiliates (31.4) (22)
-----
Total $(316.1) (19)
=======
*Reflects the year-to-date period
the increaseallocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The decline in revenues is attributable to increase in trading volume and wholesale
electricity prices.
Other operation expense increased due to increases in uncollectible
accounts and factored customer accounts receivable expenses of both the
wholesale business and energy delivery business, the effect of gains in 2000
from the disposition of emission allowances, increased trading incentive
compensation of the wholesale business and energy delivery severance accruals.
Maintenance expenses increased due to boiler overhauls at Kammer,
Mitchell, Muskingum and Sporn plants and boiler inspections at Amos and Cardinal
plants.
The commencement of amortization of transition regulatory assets in
connection with the transition to customer choice and market-based pricing of
electricity under Ohio deregulation accounted for the increase in depreciation
and amortization expense.
The increase in taxes other than federal income taxes is due to a new
State Excise Tax which produced a larger tax than the gross receipts tax it
replaced.
Federal income taxes attributable to operations decreasedmainly due to a decrease in electric
marketing and trading revenues. The decrease was driven largely by a decline in
demand due to mild winter weather and the slow recovery from the economic
recession. Heating degree days were down 12% and electricity sales to industrial
customers decreased 2%. Revenues from sales to AEP affiliates declined as a
result of the effects of the mild weather and the economy.
Operating expenses declined 20% in 2002. The changes in the components
of operating expenses were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Fuel $ (58.2) (29)
Electricity Marketing and
Trading Purchases (282.1) (24)
Purchases from AEP Affiliates (2.4) (14)
Other Operation 2.1 2
Maintenance (6.4) (18)
Depreciation and Amortization 2.6 4
Taxes Other Than Income Taxes 5.6 14
Income Taxes 3.8 12
---
Total $(335.0) (20)
=======
The decrease in fuel expense was primarily attributable to a reduction
in power generation and lower fuel costs reflecting lower market prices. Net
generation decreased by 8% due to the reduced demand for electricity. The cost
of purchased power for resale was also lower due to the reduced demand, a
continuation of the market conditions that developed in the fourth quarter of
2001.
Maintenance expense declined due primarily due to a reduction in boiler
plant overhauls.
Taxes other than income taxes increased due to changes in taxes assessed
on utilities under the Ohio Restructuring Law. The law imposed a new state
excise tax in 2002 replacing the state gross receipts tax and provided for a
reduction in taxable rates on generation property.
The increase in income taxes is predominately due to a increase in
pre-tax operating income.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $1,132,192 $1,426,817
Energy Delivery 141,760 131,849
Sales to AEP Affiliates 109,634 140,999
------- -------
TOTAL OPERATING REVENUES 1,383,586 1,699,665
--------- ---------
OPERATING EXPENSES:
Fuel 142,336 200,561
Purchased Power:
Electricity Marketing and Trading 880,157 1,162,284
AEP Affiliates 14,227 16,622
Other Operation 90,520 88,406
Maintenance 28,988 35,400
Depreciation and Amortization 62,621 60,059
Taxes Other Than Income Taxes 45,839 40,236
Income Taxes 35,182 31,341
------ ------
TOTAL OPERATING EXPENSES 1,299,870 1,634,909
--------- ---------
OPERATING INCOME 83,716 64,756
NONOPERATING INCOME 356,341 370,474
NONOPERATING EXPENSES 350,823 356,858
NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,722 2,508
INTEREST CHARGES 21,461 22,467
------ ------
NET INCOME 64,051 53,397
PREFERRED STOCK DIVIDEND REQUIREMENTS 314 314
--- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 63,737 $ 53,083
======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
NET INCOME $64,051 $53,397
OTHER COMPREHENSIVE LOSS
Foreign Currency Exchange Rate Hedge (201) (220)
---- ----
COMPREHENSIVE INCOME $63,850 $53,177
======= =======
The increase in nonoperating income was due to an increase in net gains
from the wholesale business' trading transactions outsidecommon stock of the AEP System's
traditional marketing area and speculative financial transactions (options,
futures and swaps).
Interest expense increased dueCompany is wholly owned by AEP.
See Notes to increased long-term debt outstanding.
In the second quarter ofFinancial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
we recorded an extraordinary loss of $22
million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio
deregulation (see Note 2). The application of regulatory accounting for
generation was discontinued in September 2000 which resulted in an after tax
extraordinary loss of $19 million.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,819,792 $1,484,663 $5,146,634 $3,968,830
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 167,155 188,727 547,773 581,289
Purchased Power 1,312,668 948,733 3,638,229 2,429,521
Other Operation 104,081 99,930 289,110 270,626
Maintenance 33,786 28,128 105,634 89,753
Depreciation and Amortization 59,267 39,121 176,992 116,453
Taxes Other Than Federal Income Taxes 50,507 40,579 137,561 125,366
Federal Income Taxes 22,660 42,793 69,844 114,089
------ ------ ------ -------
TOTAL OPERATING EXPENSES 1,750,124 1,388,011 4,965,143 3,727,097
--------- --------- --------- ---------
OPERATING INCOME 69,668 96,652 181,491 241,733
NONOPERATING INCOME 6,788 2,564 25,705 6,714
----- ----- ------ -----
INCOME BEFORE INTEREST CHARGES 76,456 99,216 207,196 248,447
INTEREST CHARGES 25,078 22,155 70,327 66,937
------ ------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 51,378 77,061 136,869 181,510
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION - net of tax (See note 2) - (18,876) (21,515) (18,876)
---- ------- ------- --------
NET INCOME 51,378 58,185 115,354 162,634
PREFERRED STOCK DIVIDEND REQUIREMENTS
314 315 944 951
--- --- --- ---
EARNINGS APPLICABLE TO COMMON STOCK
$ 51,064 $ 57,870 $ 114,410 $ 161,683
========== ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME $51,378 $58,185 $115,354 $162,634
OTHER COMPREHENSIVE INCOME
Foreign Currency Exchange Rate Hedge 345 - 20 -
--- ----- -- -----
COMPREHENSIVE INCOME $51,723 $58,185 $115,374 $162,634
======= =======---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $401,297 $398,086
NET INCOME 64,051 53,397
CASH DIVIDENDS DECLARED:
Common Stock 32,582 35,744
Cumulative Preferred Stock 314 314
--- ---
BALANCE AT END OF PERIOD $432,452 $415,425
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $389,945 $615,834 $398,086 $587,424
NET INCOME 51,378 58,185 115,354 162,634
CASH DIVIDENDS DECLARED:
Common Stock 35,744 158,704 107,232 234,110
Cumulative Preferred Stock 315 314 944 947
--- --- --- ---
BALANCE AT END OF PERIOD $405,264 $515,001 $405,264 $515,001
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001 December 31, 2000
------------------ -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,962,832 $2,764,155
Transmission 886,986 870,033
Distribution 1,068,738 1,040,940
General (including mining assets at December 31, 2000 See Note 3) 241,683 707,417
Construction Work in Progress 138,805 195,086
------- -------
Total Electric Utility Plant 5,299,044 5,577,631
Accumulated Depreciation and Amortization 2,422,866 2,764,130
--------- ---------
NET ELECTRIC UTILITY PLANT 2,876,178 2,813,501
--------- ---------
OTHER PROPERTY AND INVESTMENTS 65,936 109,124
------ -------
LONG-TERM ENERGY TRADING CONTRACTS 309,122 256,455
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 34,212 31,393
Advances to Affiliates - 92,486
Accounts Receivable:
Customers 100,323 139,732
Affiliated Companies 135,657 126,203
Miscellaneous 25,846 39,046
Allowance for Uncollectible Accounts (1,026) (1,054)
Fuel - at average cost 94,327 82,291
Materials and Supplies - at average cost 66,406 96,053
Energy Trading Contracts 769,154 1,617,660
Prepayments and Other 24,344 33,146
------ ------
TOTAL CURRENT ASSETS 1,249,243 2,256,956
--------- ---------
REGULATORY ASSETS 659,631 714,710
------- -------
DEFERRED CHARGES 38,914 101,690
------ -------
TOTAL ASSETS $5,199,024 $6,252,436OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $3,018,212 $3,007,866
Transmission 894,334 891,283
Distribution 1,084,329 1,081,122
General 242,446 245,232
Construction Work in Progress 201,524 165,073
------- -------
Total Electric Utility Plant 5,440,845 5,390,576
Accumulated Depreciation and Amortization 2,483,039 2,452,571
--------- ---------
NET ELECTRIC UTILITY PLANT 2,957,806 2,938,005
--------- ---------
OTHER PROPERTY AND INVESTMENTS 61,459 62,303
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 466,283 263,734
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 39,351 8,848
Accounts Receivable:
Customers 93,816 84,694
Affiliated Companies 125,302 148,563
Miscellaneous 36,835 20,409
Allowance for Uncollectible Accounts (1,048) (1,379
Fuel - at average cost 98,417 84,724
Materials and Supplies - at average cost 81,491 88,768
Accrued Utility Revenues 5,368 -
Energy Trading Contracts 685,740 472,246
Prepayments and Other 32,787 20,865
------ ------
TOTAL CURRENT ASSETS 1,198,059 927,738
--------- -------
REGULATORY ASSETS 628,491 644,625
------- -------
DEFERRED CHARGES 64,629 79,662
------ ------
TOTAL ASSETS $5,376,727 $4,916,067
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001 December 31, 2000
------------------ -----------------
(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 20 -
Retained Earnings 405,264 398,086
------- -------
Total Common Shareholder's Equity 1,188,968 1,181,770
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,648 16,648
Subject to Mandatory Redemption 8,850 8,850
Long-term Debt 981,380 1,077,987
Long-term Debt - Affiliated Company 300,000 -
------- ----
TOTAL CAPITALIZATION 2,495,846 2,285,255
--------- ---------
OTHER NONCURRENT LIABILITIES 136,600 542,017
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 117,506
Advances from Affiliates 360,048 -
Accounts Payable - General 160,717 179,691
Accounts Payable - Affiliated Companies 70,661 121,360
Customer Deposits 8,993 39,736
Taxes Accrued 25,876 223,101
Interest Accrued 30,054 20,458
Obligations Under Capital Leases 14,180 32,716
Energy Trading Contracts 719,697 1,662,315
Other 121,306 151,934
------- -------
TOTAL CURRENT LIABILITIES 1,511,532 2,548,817
--------- ---------
DEFERRED INCOME TAXES 753,689 621,941
------- -------
DEFERRED INVESTMENT TAX CREDITS 22,875 25,214
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 266,545 206,187
------- -------
REGULATORY LIABILITIES AND DEFERRED CREDITS 11,937 23,005
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,199,024 $6,252,436OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(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) (397) (196)
Retained Earnings 432,452 401,297
------- -------
Total Common Shareholder's Equity 1,215,739 1,184,785
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,648 16,648
Subject to Mandatory Redemption 8,850 8,850
Long-term Debt 1,199,009 1,203,841
--------- ---------
TOTAL CAPITALIZATION 2,440,246 2,414,124
--------- ---------
OTHER NONCURRENT LIABILITIES 126,924 130,386
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 5,000 -
Advances from Affiliates 389,386 300,213
Accounts Payable - General 124,685 134,418
Accounts Payable - Affiliated Companies 110,429 176,520
Customer Deposits 5,961 5,452
Taxes Accrued 148,268 126,770
Interest Accrued 24,850 17,679
Obligations Under Capital Leases 14,219 16,405
Energy Trading Contracts 656,059 456,047
Other 77,898 87,070
------ ------
TOTAL CURRENT LIABILITIES 1,556,755 1,320,574
--------- ---------
DEFERRED INCOME TAXES 796,885 797,889
------- -------
DEFERRED INVESTMENT TAX CREDITS 21,160 21,925
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 410,895 214,487
------- -------
DEFERRED CREDITS 23,862 16,682
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,376,727 $4,916,067
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 115,354 $ 162,634$64,051 $53,397
Adjustments for Noncash Items:
Depreciation 134,105 145,12543,196 52,853
Amortization of Transition Assets 55,029 -19,425 19,256
Deferred Federal Income Taxes 182,166 (2,058)
Deferred Fuel Costs (net) - (33,259)(4,649) (1,068)
Amortization of Deferred Property Taxes 61,821 60,297
Extraordinary Loss - Discontinuance SFAS 71 21,515 18,876
Capital Lease Obligation- Noncurrent (15,104) (15,489)
Accumulated Provisions- Noncurrent (390,313) 7,26814,717 19,992
Mark to Market of Energy Trading Contracts (16,055) (45,268)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 43,127 60,383(2,618) 1,274
Fuel, Materials and Supplies 17,611 60,686(6,416) (17,131)
Accrued Utility Revenues (5,368) 264
45,575
Prepayments and Other Current Assets 8,538 3,624(11,822) (22,537)
Accounts Payable (69,673) 7,654(75,824) (34,942)
Customer Deposits (30,743) (2,711)509 89,622
Taxes Accrued (197,225) (21,355)21,498 (51,420)
Interest Accrued 9,596 6,060
Energy Trading Contract (net) (86,421) (7,067)7,171 11,106
Other (net) (26,038) 52,475Operating Assets 1,388 1,267
Other Operating Liabilities (8,819) (24,848)
------ ------- ------
Net Cash Flows From (Used For) Operating Activities (166,391) 548,718
-------- -------40,384 51,817
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (242,898) (143,717)(66,312) (65,103)
Proceeds from Sale of Property and Other 16,562 4,404
Investment in Coal Companies (32,115) -
-------154 5,885
--- -----
Net Cash Flows Used For Investing Activities (258,451) (139,313)
-------- --------(66,158) (59,218)
------- -------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - Affiliated 300,000 -
Issuance of Long-term Debt - 74,748
Change in Advances to Affiliates (net) 452,534 (149,616)
Change in Short-term Debt (net) - (194,918)
Retirement of Cumulative Preferred Stock - (182)89,173 75,950
Retirement of Long-term Debt (216,697) (26,538)- (42,506)
Dividends Paid on Common Stock (107,232) (234,110)(32,582) (35,744)
Dividends Paid on Cumulative Preferred Stock (944) (947)(314) (314)
---- ----
Net Cash Flows From (Used For) Financing Activities 427,661 (531,563)
------- --------56,277 (2,614)
------ ------
Net Increase (Decrease) in Cash and Cash Equivalents 2,819 (122,158)30,503 (10,015)
Cash and Cash Equivalents at Beginning of Period 8,848 31,393
157,138----- ------ -------
Cash and Cash Equivalents at End of Period $ 34,212 $ 34,980
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $59,492,000$39,351 $21,378
======= =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $13,900,000 and
$10,887,000 and for income taxes was $(5,574,000) and $50,242,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $98,000 and
$319,000 in 2002 and
$59,963,000 and for income taxes was $55,806,000 and $56,813,000 in 2001, and
2000, respectively. Noncash acquisitions under capital leases were $595,000 and
$12,734,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses:PSO is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 503,000 retail
customers in eastern and southwestern Oklahoma. PSO also sells electric power at
wholesale which consists of generation,
retail electricity sales,to other utilities, municipalities and rural electric cooperatives.
Wholesale power marketing and trading activities are conducted on PSO's
behalf by AEPSC. PSO, along with the other AEP electric operating subsidiaries,
shares in the forward trades with other utility systems and power marketers.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a cost-based rate-regulated electric public utility
company, PSO's consolidated financial statements reflect the actions of
electricity;regulators that can result in the recognition of revenues and energy
delivery which consistsexpenses in
different time periods than enterprises that are not rate regulated. In
accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. SinceThe revenues are recognized in our income
statement when the merger ofenergy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP and CSWengages in June 2000, we participate in the AEP System's powerwholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to PSO. Trading
activities allocated to PSO involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
Accounting standards applicable to trading activities require that
changes in the fair value of trading contracts be recognized in revenues prior
to settlement and is commonly referred to as mark-to-market (MTM) accounting.
Since PSO is a cost-based rate-regulated entity, whose revenues are based on
settled transactions, unrealized changes in the fair value of physical forward
sale and purchase contracts are deferred as regulatory liabilities (gains) or
regulatory assets (losses).
Mark-to-market accounting represents the change in the unrealized
gain or loss throughout the contract's term. When the contract actually settles,
that is, the energy is actually delivered in a sale or received in a purchase or
the parties agree to forego delivery and receipt and net settle in cash, the
unrealized gain or loss is reversed and the actual realized cash gain or loss is
recognized in the income statement. Therefore, as the contract's market value
changes over the contract's term an unrealized gain or loss is deferred as a
regulatory liability or a regulatory asset. When the contract settles the total
gain or loss is realized in cash and recognized in the income statement.
Physical forward trading sale contracts are included in revenues when the
contracts settle. Physical forward trading purchase contracts are included in
purchased power expense when they settle. Prior to settlement, changes in the
fair value of physical forward sale and purchase contracts are deferred as
regulatory liabilities (gains) or regulatory assets (losses). Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due. Liquidity risk represents the risk that imperfections in the market
will cause the price to be less than or more than what the price should be based
purely on supply and demand. There are inherent risks related to the underlying
assumptions in models used to fair value open long-term trading contracts. AEP
has independent controls to evaluate the reasonableness of our valuation models.
However, energy markets, especially electricity markets, are imperfect and
volatile and unforeseen events can and will cause reasonable price curves to
differ from actual prices throughout a contract's term and when contracts
settle. Therefore, there could be significant adverse or favorable effects on
future results of operations and cash flows if market prices at settlement do
not correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing PSO to market risk. See "Quantitative and
Qualitative Disclosures about Market Risk" section for a discussion of the
policies and procedures used to manage exposure to risk from trading activities.
Net income decreased $3.3Results of Operations
The net loss incurred by PSO increased $0.1 million or 6%5.6% in 2002
primarily as a result of increased maintenance expense due to storm damage in
2002.
The following analyzes the third quarter and $8.8
million or 12%changes in the first nine months of 2001 due primarily from last year's
inclusion of a gain on the sale of a minority interest in Scientech, Inc. Income
statement line items which changed significantly were:operating revenues:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) %-------------------
(in millions) %
------------- -
------------- -Electricity Marketing
and Trading* $(102.6) (35)
Energy Delivery* 3.3 7
Sales to AEP Affiliates (9.0) (81)
----
Total Revenues $(108.3) (30)
=======
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
Operating Revenues $355 64 $739 80
Fuel Expense (1) (1) 109 36
Purchased Power Expense 351 144 614 208
Other Operation Expense 1 2 17 21
Maintenance 3 36 4 12
Federal Income Taxes (3) (9) (7) (20)
Nonoperating Income (7) (97) (7) (89)
The significant increase in revenues for the quarter resulted from
increased trading volumes of the wholesale business. In the year-to-date period,
the increase in revenues is primarily attributable to our participation in AEP's
power marketing and trading operations. Revenues for the year-to-date period
also increased as a result of an adjustment in 2000 under a FERC-approved
Transmission Coordination Agreement, which decreased revenues and other
operation expenses in 2000. The Transmission Coordination Agreement provides the
means by which the AEP West electric operating companies plan, operate and
maintain their four separate transmission systems as a single unit. The
agreement also established the method by which these companies allocate revenues
and costs received under open access transmission tariffs.
Fuel expense increased year-to-date due primarily to a rise in the
average unit fuel cost reflecting an increase in natural gas prices.
The increase in purchased power expense was primarily attributable to
our participation in the AEP System's power marketing and trading activities.
Year-to-date other operation expenses increased due mainly to a
favorable adjustment in 2000 under the FERC-approved Transmission Coordination
Agreement mentioned above, along with increased incentive compensation for power
trading and transmission expenses.
Maintenance expense increased year-to-date due to scheduled power plant
maintenance and additional expenses related to a January ice storm. Maintenance
for the quarter increased due to scheduled power plant maintenance.
Federal income tax expense associated with operations decreased as a result of a decline in pre-tax book income.fuel recovery
revenue and a decline in our share of AEP's marketing and trading operations.
The decrease in nonoperatingelectric marketing and trading revenue was driven largely by a
decline in demand due to mild winter weather and the slow recovery from the
economic recession. Lower energy demand depressed margins from electric
marketing and trading.
Operating expenses are as follows:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Fuel $ (53.7) (48)
Electricity Marketing
and Trading Purchases (32.7) (25)
Purchases from AEP Affiliates (20.5) (55)
Other Operation (7.9) (23)
Maintenance 4.3 44
Depreciation and Amortization 1.4 7
Taxes Other Than Income Taxes 0.1 N.M.
Income Taxes 0.6 28
---
Total $(108.4) (31)
=======
N.M. = Not Meaningful
The decrease in fuel expense was primarily due to lower fuel costs
reflecting lower market prices for natural gas and fuel oil.
The cost per megawatt hour of purchased power was lower due to reduced
demand, a continuation of the market conditions that developed in the fourth
quarter of 2001.
Other operation expense decreased due mainly to reduced power trading
incentive accruals, lower transmission wheeling charges and reduced factoring
and collections expenses.
Maintenance expense increased largely as a result of increased expenses
to repair damage to overhead lines caused by a winter storm in 2002.
Depreciation expense increased due to the cost of repowering Northeast
Station Units 1 & 2.
The increase in income primarily resulted from last
year's inclusion oftaxes is predominately due to an increase in
pre-tax income, and changes in certain book/tax timing differences accounted for
on a gain onflow through basis.
Lower interest rates and a reduction in outstanding borrowings caused
the sale of a minorityreduction in interest in Scientech, Inc.charges.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $910,428 $555,236 $1,664,761 $925,738
-------- -------- ---------- --------
OPERATING EXPENSES:
Fuel 154,177 155,103 411,905 302,497
Purchased Power 593,577 242,852 909,384 295,059
Other Operation 32,970 32,235 101,859 84,468
Maintenance 10,886 8,032 33,575 30,027
Depreciation and Amortization 20,313 19,632 59,458 57,470
Taxes Other Than Federal Income Taxes 12,914 12,660 29,837 28,718
Federal Income Taxes 25,677 28,285 28,548 35,700
------ ------- ------ ------
TOTAL OPERATING EXPENSES 850,514 498,799 1,574,566 833,939
------- ------- --------- -------
OPERATING INCOME 59,914 56,437 90,195 91,799
NONOPERATING INCOME 213 7,211 908 7,927
--- ----- --- -----
INCOME BEFORE INTEREST CHARGES 60,127 63,648 91,103 99,726
INTEREST CHARGES 9,058 9,319 29,674 29,532
----- ----- ------ ------
NET INCOME 51,069 54,329 61,429 70,194
PREFERRED STOCK DIVIDEND REQUIREMENTS
53 52 159 158
-- -- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 51,016 $ 54,277 $ 61,270 $ 70,036
======== ========PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $194,024 $296,599
Energy Delivery 51,732 48,417
Sales to AEP Affiliates 2,094 11,123
----- ------
TOTAL OPERATING REVENUES 247,850 356,139
------- -------
OPERATING EXPENSES:
Fuel 58,097 111,801
Purchased Power:
Electricity Marketing and Trading 96,520 129,179
AEP Affiliates 16,845 37,367
Other Operation 26,639 34,557
Maintenance 14,169 9,830
Depreciation and Amortization 20,916 19,471
Taxes Other Than Income Taxes 7,848 7,793
Income Taxes (1,594) (2,199)
------ ------
TOTAL OPERATING EXPENSES 239,440 347,799
------- -------
OPERATING INCOME 8,410 8,340
NONOPERATING INCOME 106 824
NONOPERATING EXPENSES 595 336
NONOPERATING INCOME TAX CREDIT (141) (115)
INTEREST CHARGES 9,710 10,503
----- ------
NET LOSS (1,648) (1,560)
PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53
-- --
EARNINGS LOSS APPLICABLE TO COMMON STOCK $ (1,701) $ (1,613)
======== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $121,822 $120,995 $137,688 $139,236
NET INCOME 51,069 54,329 61,429 70,194
CASH DIVIDENDS DECLARED:
Common Stock 13,060 17,000 39,180 51,000
Preferred Stock 53 52 159 158
-- -- --- ---
BALANCE AT END OF PERIOD $159,778 $158,272 $159,778 $158,272
======== ========CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $142,994 $137,688
NET LOSS (1,648) (1,560)
CASH DIVIDENDS DECLARED:
Common Stock 22,455 13,060
Preferred Stock 53 53
-- --
BALANCE AT END OF PERIOD $118,838 $123,015
======== ========
The common stock of PSO is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,040,043 $1,034,711
Transmission 430,395 427,110
Distribution 989,002 972,806
General 200,141 203,572
Construction Work in Progress 40,799 56,900
------ ------
Total Electric Utility Plant 2,700,380 2,695,099
Accumulated Depreciation and Amortization 1,199,198 1,184,443
--------- ---------
NET ELECTRIC UTILITY PLANT 1,501,182 1,510,656
--------- ---------
OTHER PROPERTY AND INVESTMENTS 41,425 41,020
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 22,890 55,215
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 7,841 5,795
Accounts Receivable:
Customers 37,214 31,100
Affiliated Companies 8,524 10,905
Fuel - at LIFO costs 21,074 21,559
Materials and Supplies - at average costs 38,616 36,785
Energy Trading Contracts 37,507 162,200
Prepayments 1,861 2,368
----- -----
TOTAL CURRENT ASSETS 152,637 270,712
------- -------
REGULATORY ASSETS 29,791 35,004
------ ------
DEFERRED CHARGES 25,831 5,290
------ -----
TOTAL ASSETS $1,773,756 $1,917,897
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001March 31, 2002 December 31, 2000
------------------ -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,037,025 $914,096
Transmission 418,793 396,695
Distribution 972,827 938,053
General 204,981 206,731
Construction Work in Progress 35,776 149,095
------ -------
Total Electric Utility Plant 2,669,402 2,604,670
Accumulated Depreciation and Amortization 1,175,621 1,150,253
--------- ---------
NET ELECTRIC UTILITY PLANT 1,493,781 1,454,417
--------- ---------
OTHER PROPERTY AND INVESTMENTS 40,384 38,211
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 72,313 52,629
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 7,569 11,301
Accounts Receivable:
Customers 22,964 59,957
Affiliated Companies 5,912 3,453
Fuel - at LIFO costs 15,320 28,113
Materials and Supplies - at average costs 32,791 29,642
Under-recovered Fuel Costs - 43,267
Energy Trading Contracts 259,930 382,380
Prepayments 3,188 1,559
----- -----
TOTAL CURRENT ASSETS 347,674 559,672
------- -------
REGULATORY ASSETS 29,650 29,338
------ ------
DEFERRED CHARGES 17,580 7,889
------ -----
TOTAL ASSETS $2,001,382 $2,142,156
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001
December 31, 2000
-------------------------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000 Shares
Issued Shares: 10,482,000 shares and
Outstanding Shares: 9,013,000 Shares $ 157,230 $ 157,230$157,230 $157,230
Paid-in Capital 180,000 180,000
Retained Earnings 159,778 137,688118,838 142,994
------- -------
Total Common Shareholder's Equity 497,008 474,918456,068 480,224
Cumulative Preferred Stock Not Subject
to Mandatory Redemption 5,283 5,283
PSO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of PSO 75,000 75,000
Long-term Debt 451,052 450,822345,205 345,129
------- -------
TOTAL CAPITALIZATION 1,028,343 1,006,023
--------- ---------881,556 905,636
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 20,000106,000 106,000
Advances from Affiliates 58,426 81,120186,997 123,087
Accounts Payable - General 38,510 104,37946,658 72,759
Accounts Payable - Affiliated Companies 32,686 64,55635,531 40,857
Customers Deposits 19,137 19,294
Over-recovered21,547 21,041
Over-Recovered Fuel Costs 24,708 -11,100 8,720
Taxes Accrued 72,522 1,65927,557 18,150
Interest Accrued 12,107 8,33611,365 7,298
Energy Trading Contracts 260,800 389,27943,403 167,658
Other 13,769 12,137
------9,637 12,296
----- ------
TOTAL CURRENT LIABILITIES 532,665 700,760499,795 577,866
------- -------
DEFERRED INCOME TAXES 288,614 312,060299,232 296,877
------- -------
DEFERRED INVESTMENT TAX CREDITS 34,440 35,78333,544 33,992
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 39,407 35,29238,469 56,203
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 77,913 52,23821,160 47,323
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $2,001,382 $2,142,156$1,773,756 $1,917,897
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $(1,648) $ 61,429 $ 70,194(1,560)
Adjustments for Noncash Items:
Depreciation and Amortization 59,458 57,47020,916 19,471
Deferred Income Taxes (25,491) 19,7981,886 5,750
Deferred Investment Tax Credits (1,343) (1,343)
Amortization of Deferred Property Taxes (8,568) -(448) (448)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 34,534 (34,933)(3,733) (4,018)
Fuel, Materials and Supplies 9,644 158
Other Deferred Credits 1,997 22,627(1,346) 5,864
Accounts Payable (97,739) 50,079(31,427) (35,424)
Taxes Accrued 70,863 12,685
Other9,407 4,738
Deferred Property and Investments (1,814) (30,331)Taxes (21,210) (20,730)
Fuel Recovery 67,975 (35,340)2,380 (2,724)
Mark to Market of Energy Trading Contracts (104) -
Changes in Other (net) (4,090) 12,150Assets 765 (832)
Changes in Other Liabilities (4,235) (3,101)
------ ------
Net Cash Flows FromUsed For Operating Activities 166,855 143,214(28,797) (33,014)
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (88,194) (120,105)(10,559) (28,595)
Other - (359)
------ ---- ------
Net Cash Flows Used For Investing Activities (88,553) (120,105)(10,559) (28,954)
------- ---------------
FINANCING ACTIVITIES:
Retirement of Long-term Debt - (20,000) (10,000)
Change in Advances fromFrom Affiliates (net) (22,695) 40,52063,910 97,872
Dividends Paid on Common Stock (39,180) (51,000)(22,455) (13,060)
Dividends Paid on Cumulative Preferred Stock (159) (158)
---- ----(53) (53)
--- ---
Net Cash Flows From Financing Activities (82,034) (20,638)
-------41,402 64,759
------ ------
Net Increase in Cash and Cash Equivalents (3,732) 2,4712,046 2,791
Cash and Cash Equivalents at Beginning of Period 5,795 11,301
3,173----- ------ -----
Cash and Cash Equivalents at End of Period $ 7,5697,841 $ 5,644
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $24,351,00014,092
======= ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $5,157,000 and $5,736,000
and for income taxes was $1,783,000 and $1,978,000 in 2002 and
$24,222,000 and for income taxes was $7,386,000 and $13,925,000 in 2001, and
2000,
respectively.
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRDFIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses:SWEPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in northeastern Texas,
northwestern Louisiana, and western Arkansas. SWEPCo also sells electric power
at wholesale which consists of generation,
retail electricity sales,to other utilities, municipalities and rural electric cooperatives.
Wholesale power marketing and trading activities are conducted on
SWEPCo's behalf by AEPSC. SWEPCo, along with the other AEP electric operating
subsidiaries, shares in AEP's forward trades with other utility systems and
power marketers.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - Our financial statements reflect the actions of
electricity;regulators since our electricity supply sales in the Louisiana jurisdiction and
energy
delivery which consists ofour transmission and distribution services. Sinceoperations are cost-based rate-regulated. As a
result of the mergerregulators' actions, our financial statements can recognize
revenues and expenses in different time periods than enterprises that are not
rate regulated. In accordance with SFAS 71, regulatory assets (deferred
expenses) and regulatory liabilities (future revenue reductions or refunds) are
recorded to reflect the economic effects of AEP and CSW in June 2000, we participateregulation by matching expenses with
their recovery through regulated revenues in the same accounting period.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Energy Marketing and Trading Activities - AEP System's powerengages in wholesale electricity
marketing and trading activities.
Net income increased $10 million, or 14%, fortransactions (trading activities). A portion of the
year-to-date period
despite a decreaserevenues and costs of AEP's trading activities are allocated to SWEPCo. Trading
activities allocated to SWEPCo involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We generally recognize revenues from open trading activities based on changes in
the quarterfair value of $1 million,energy trading contracts.
Recording the net change in the fair value of open trading contracts
as revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. Under MTM accounting the change in the unrealized gain or 2%. The increaseloss
throughout a contract's term is recognized in each accounting period. When the
contract actually settles, that is, the energy is actually delivered in a sale
or received in a purchase or the parties agree to forego delivery and receipt
and net settle in cash, the unrealized gain or loss is reversed out of revenues
and the actual realized cash gain or loss is recognized in revenues for the
year-to-date period resulted from the favorable impact of our participationa sale
or in
AEP's power marketing and trading operations. Income statement line items which
changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $455 79 $835 79
Fuel Expense (38) (22) 1 -
Purchased Power Expense 483 219 789 314
Other Operation Expense 7 18 8 8
Maintenance 3 21 3 7
Depreciation and Amortization - N.M. 11 15
Taxes Other Than Federal Income Taxes 1 7 6 15
Federal Income Taxes - N.M. 6 19
N.M. = Not Meaningful
The significant increase in operating revenues and purchased power expense for a purchase. Therefore, over the quarter resulted from increased trading
volumescontract's term an unrealized gain or loss is recognized as the contract's
market value changes. When the contract settles the total gain or loss is
realized in cash but only the difference between the accumulated unrealized net
gains or losses recorded in prior months and the cash proceeds is recognized.
Unrealized mark-to-market gains and losses are included in the Balance Sheet as
energy trading contract assets or liabilities.
Our trading activities represent physical forward electricity contracts
that are typically settled by entering into offsetting contracts. An example of
our trading activities is when, in January, we enter into a forward sales
contract to deliver electricity in July. At the wholesale
business.end of each month until the
contract settles in July, we would record any difference between the contract
price and the market price as an unrealized gain or loss in revenues. In July
when the year-to-date period,contract settles, we would realize a gain or loss in cash and reverse
to revenues the increasepreviously recorded cumulative unrealized gain or loss. Prior to
settlement, the change in the fair value of physical forward sale and purchase
contracts is included in revenues on a net basis. Upon settlement of a forward
trading contract, the amount realized is included in revenues for a sales
contract and realized cost is included in purchased power expense for a purchase
contract with the prior change in unrealized fair value reversed in revenues.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match, then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts from this point forward will have no further impact on
results of operations but will have an offsetting and equal effect on trading
contract assets and liabilities. Of course we could also attributabledo similar transactions
but enter into a purchase contract prior to entering into a sales contract. If
the sale and purchase contracts do not match exactly as to volumes, delivery
point, schedule and other key terms, then there could be continuing
mark-to-market effects on revenues from recording additional changes in fair
values using mark-to-market accounting.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
participationvaluation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices at
settlement do not correlate with the AEP-developed price models.
Volatility in AEP's powercommodities markets affects the fair values of all of our
open trading contracts exposing SWEPCo to market risk. See "Quantitative and
Qualitative Disclosures about Market Risk" section for a discussion of the
policies and procedures used to manage exposure to risk from trading activities.
Results of Operations
Net income decreased $12.7 million or 64% for the quarter. The decrease
resulted primarily from reduced wholesale prices and margins due to a decline in
demand for electricity which resulted from mild winter weather and a slow
economic recovery.
Operating revenues decreased 22% in 2002 because of a significant
decrease in wholesale marketing and trading operations.
Fuel expense of the wholesale business decreased for the quarter due
primarily to a decreaserevenues. The changes in the
average unit costcomponents of fuelrevenues were as follows:
Increase (Decrease)
(in millions) %
Electricity Marketing
and Trading* $(80.1) (25)
Energy Delivery* (9.1) (12)
Sales to AEP Affiliates (5.7) (20)
----
Total $(94.9) (22)
======
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
Operating revenues decreased in 2002 as a result of reduced wholesale
prices due to reduced energy demand as a result of the mild winter weather and
the slow recovery from the economic recession.
Operating expenses decreased by 21% in 2002 mostly due to a significant
decrease in electricity marketing and trading purchases and fuel expense.
Increase (Decrease)
-------------------
(in millions) %
------------- -
Fuel $(29.3) (25)
Electricity Marketing and
Trading Purchases (43.7) (28)
Purchases from AEP Affiliates (5.6) (40)
Other Operation 2.9 7
Maintenance (3.4) (22)
Depreciation and Amortization 2.0 7
Taxes Other Than Income Taxes 0.2 1
Income Taxes (5.5) (71)
----
Total $(82.4) (21)
======
Fuel expense decreased due to lower
spot market natural gas prices.prices as a result of a
mild winter and the slow recovery from the economic recession that started in
the fourth quarter of 2001.
A milder than normal winter and decreasing purchased power prices
resulted in decreases to both electricity marketing and trading purchases and
electricity purchases from AEP affiliates.
Due to the acquisition of Dolet Hills mining operation in June 2001,
other operation expense increased for the quarterin 2002.
Maintenance expense decreased as a result of costs incurred last year to
restore service and year-to-date periods.
Although tree-trimming expenses increased in the third quarter of 2001,
they were slightly lower for the year-to-date period. Repairs to overhead lines
because ofmake repairs following a severe ice stormsstorm.
The increase in the first quarter of 2001 made maintenance
expense increase for the year-to-date period.
Depreciationdepreciation and amortization expense increased year-to-datewas due primarily
to an increase in excess earnings accruals under the Texas
restructuring legislation and the acquisition of the Dolet Hills mining operation.
Taxes other than federal incomeIncome taxes increased during the quarter dueattributable to increased state income taxes reflecting higher state taxable income. Taxes
other than federal income taxes increased year-to-dateoperations decreased due to a favorable
adjustmentsignificant
decrease in pre-tax income.
Nonoperating income decreased due primarily to a reduction in interest
income earned on under-recovered fuel which resulted from significant natural
gas price increases in the second half of ad valorem taxes recorded in 2000 and increased state taxableearly 2001. During 2001 gas
price declines and a PUCT approved fuel rate and fuel surcharge increases
lowered the unrecovered fuel balance thus lowering interest income. The increaseAlso a
decrease in federal income tax expense attributable to operations
was primarilyallowance for funds used during construction due to an increase in pre-tax operatinglower
construction balances reduced nonoperating income.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,028,742 $573,891 $1,889,226 $1,054,056
---------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 134,560 172,763 376,957 375,888
Purchased Power 702,899 220,114 1,040,427 251,064
Other Operation 46,631 39,417 119,970 111,477
Maintenance 15,344 12,644 51,011 47,856
Depreciation and Amortization 28,461 27,978 89,919 78,460
Taxes Other Than Federal Income Taxes 18,754 17,518 48,006 41,634
Federal Income Taxes 21,899 22,145 36,107 30,338
------ ------ ------ ------
TOTAL OPERATING EXPENSES 968,548 512,579 1,762,397 936,717
------- ------- --------- -------
OPERATING INCOME 60,194 61,312 126,829 117,339
NONOPERATING INCOME 627 1,008 904 1,453
--- ----- --- -----
INCOME BEFORE INTEREST CHARGES 60,821 62,320 127,733 118,792
INTEREST CHARGES 14,464 14,783 43,723 44,806
------ ------ ------ ------
NET INCOME 46,357 47,537 84,010 73,986
PREFERRED STOCK DIVIDEND REQUIREMENTS
57 58 172 172
-- -- --- ---
EARNINGS APPLICABLE TO
COMMON STOCK $ 46,300 $ 47,479 $ 83,838 $ 73,814
========= ======== ========SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $238,854 $318,986
Energy Delivery 68,935 78,057
Sales to AEP Affiliated 22,959 28,646
------ ------
TOTAL OPERATING REVENUES 330,748 425,689
------- -------
OPERATING EXPENSES:
Fuel 88,883 118,246
Purchased Power:
Electricity Marketing and Trading 111,095 154,795
AEP Affiliated 8,441 14,062
Other Operation 42,151 39,268
Maintenance 11,838 15,236
Depreciation and Amortization 30,140 28,130
Taxes Other Than Income Taxes 14,466 14,266
Income Taxes 2,234 7,700
----- -----
TOTAL OPERATING EXPENSES 309,248 391,703
------- -------
OPERATING INCOME 21,500 33,986
NONOPERATING INCOME 102 834
NONOPERATING EXPENSES 566 640
NONOPERATING INCOME TAX EXPENSE (CREDIT) 28 (53)
INTEREST CHARGES 13,818 14,364
------ ------
NET INCOME 7,190 19,869
PREFERRED STOCK DIVIDEND REQUIREMENTS 57 57
-- --
EARNINGS APPLICABLE TO COMMON STOCK $7,133 $ 19,812
====== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $294,422 $278,881 $293,989 $283,546
NET INCOME 46,357 47,537 84,010 73,986
CASH DIVIDENDS DECLARED:
Common Stock 18,554 15,500 55,659 46,500
Preferred Stock 57 58 172 172
-- -- --- ---
BALANCE AT END OF PERIOD $322,168 $310,860 $322,168 $310,860
======== ========CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $308,915 $293,989
NET INCOME 7,190 19,869
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 18,964 18,553
Preferred Stock 57 57
-- --
BALANCE AT END OF PERIOD $297,084 $295,248
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001 December 31, 2000
------------------ -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,432,242 $1,414,527
Transmission 537,835 519,317
Distribution 1,033,083 1,001,237
General 375,603 325,948
Construction Work in Progress 50,650 57,995
------ ------
Total Electric Utility Plant 3,429,413 3,319,024
Accumulated Depreciation and Amortization 1,525,936 1,457,005
--------- ---------
NET ELECTRIC UTILITY PLANT 1,903,477 1,862,019
--------- ---------
OTHER PROPERTY AND INVESTMENTS 42,213 39,627
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 86,306 63,028
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 4,650 1,907
Accounts Receivable:
Customers 70,192 41,399
Affiliated Companies 2,283 11,419
Fuel Inventory - at average cost 36,648 40,024
Under-recovered Fuel 19,445 35,469
Materials and Supplies - at average cost 31,342 25,137
Energy Trading Contracts 314,306 457,936
Prepayments 19,729 16,780
------ ------
TOTAL CURRENT ASSETS 498,595 630,071
------- -------
REGULATORY ASSETS 53,156 57,082
------ ------
DEFERRED CHARGES 78,567 10,707
------ ------
TOTAL ASSETS $2,662,314 $2,662,534SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,440,947 $1,429,356
Transmission 561,473 538,749
Distribution 1,049,876 1,042,523
General 375,438 376,016
Construction Work in Progress 38,948 74,120
------ ------
Total Electric Utility Plant 3,466,682 3,460,764
Accumulated Depreciation and Amortization 1,574,868 1,550,618
--------- ---------
NET ELECTRIC UTILITY PLANT 1,891,814 1,910,146
--------- ---------
OTHER PROPERTY AND INVESTMENTS 43,561 43,000
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 26,271 63,372
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 1,888 5,415
Accounts Receivable:
Customers 48,236 44,588
Affiliated Companies 18,067 12,069
Allowance for Uncollectible Accounts (250) (89)
Fuel Inventory - at average cost 69,845 52,212
Under-recovered Fuel - 2,501
Materials and Supplies - at average cost 33,398 32,527
Energy Trading Contracts 43,047 186,159
Prepayments 16,127 18,716
------ ------
TOTAL CURRENT ASSETS 230,358 354,098
------- -------
REGULATORY ASSETS 49,211 51,989
------ ------
DEFERRED CHARGES 91,325 67,753
------ ------
TOTAL ASSETS $2,332,540 $2,490,358
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001 December 31, 2000
------------------ -----------------
(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 245,000 245,000
Retained Earnings 322,168 293,989
------- -------
Total Common Shareowner's Equity 702,828 674,649
Preferred Stock 4,704 4,704
SWEPCO-Obligated, Mandatorily Redeemable Preferred Securities
Of Subsidiary Trust Holding Solely Junior Subordinated
Debentures Of SWEPCO 110,000 110,000
Long-term Debt 494,855 645,368
------- -------
TOTAL CAPITALIZATION 1,312,387 1,434,721
--------- ---------
OTHER NONCURRENT LIABILITIES 33,810 11,290
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 150,595 595
Advances from Affiliates 78,931 16,823
Accounts Payable - General 54,042 107,747
Accounts Payable - Affiliated Companies 30,909 36,021
Customer Deposits 15,698 16,433
Taxes Accrued 74,877 11,224
Interest Accrued 14,697 13,198
Energy Trading Contracts 314,475 466,198
Other 24,767 15,064
------ ------
TOTAL CURRENT LIABILITIES 758,991 683,303
------- -------
DEFERRED INCOME TAXES 399,717 399,204
------- -------
DEFERRED INVESTMENT TAX CREDITS 49,846 53,167
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 20,432 18,288
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 87,131 62,561
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $2,662,314 $2,662,534SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(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 245,000 245,000
Retained Earnings 297,084 308,915
------- -------
Total Common Shareowner's Equity 677,744 689,575
Preferred Stock 4,704 4,704
SWEPCO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of SWEPCO 110,000 110,000
Long-term Debt 494,217 494,688
------- -------
TOTAL CAPITALIZATION 1,286,665 1,298,967
--------- ---------
OTHER NONCURRENT LIABILITIES 36,197 34,997
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 595 150,595
Advances from Affiliates 272,326 117,367
Accounts Payable - General 68,939 71,810
Accounts Payable - Affiliated Companies 39,186 37,469
Customer Deposits 20,596 19,880
Taxes Accrued 63,253 36,522
Interest Accrued 13,697 13,631
Energy Trading Contracts 49,709 192,318
Over-recovered Fuel 7,613 -
Other 20,801 26,166
------ ------
TOTAL CURRENT LIABILITIES 556,715 665,758
------- -------
DEFERRED INCOME TAXES 366,113 369,781
------- -------
DEFERRED INVESTMENT TAX CREDITS 47,583 48,714
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 14,982 17,828
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 24,285 54,313
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $2,332,540 $2,490,358
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 84,0107,190 $ 73,98619,869
Adjustments for Noncash Items:
Depreciation and Amortization 89,919 78,46030,140 28,130
Deferred Income Taxes (2,534) 10,901(3,930) (1,930)
Deferred Investment Tax Credits (3,321) (3,361)
Deferred Property Taxes (9,316) -(1,131) (1,113)
Mark-to-Market of Energy Trading Contracts 4,498 (5,316)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (19,657) (17,515)(9,485) 21,669
Fuel, Materials and Supplies 943 1,367(18,504) (662)
Accounts Payable (58,817) 31,267(1,154) (49,324)
Taxes Accrued 63,653 23,083
Transmission Coordination Agreement Settlement - (24,406)26,731 32,119
Deferred Property Taxes (27,217) (24,636)
Fuel Recovery 16,024 (36,977)10,114 (6,637)
Change in Other (1,193) 12,250Assets 19,981 (1,391)
Change in Other Liabilities (2,009) (13,280)
------ -------------
Net Cash Flows From (Used For) Operating Activities 159,711 149,055
------- -------22,700 (2,502)
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (76,668) (92,147)
Purchase of Dolet Hills Mining Operations (85,716)(11,715) (21,638)
Other - Other (411) -
----- -------326
---- ---
Net Cash Flows Used For Investing Activities (162,795) (92,147)
--------(11,715) (21,312)
------- -------
FINANCING ACTIVITIES:
Redemption of Preferred Stock - (1)
Issuance of Long-term Debt - 149,634
Retirement of Long-term Debt (150,450) (450) (45,450)
Change in Advances from Affiliates (net) 62,108 (113,950)154,959 43,482
Dividends Paid on Common Stock (55,659) (46,500)(18,964) (18,553)
Dividends Paid on Cumulative Preferred Stock (172) (172)
---- ----(57) (57)
--- ---
Net Cash Flows From (Used For) Financing Activities 5,827 (56,439)
-----(14,512) 24,422
------- ------
Net Increase (Decrease) in Cash and Cash Equivalents 2,743 469(3,527) 608
Cash and Cash Equivalents at Beginning of Period 5,415 1,907 3,043
----- -----
Cash and Cash Equivalents at End of Period $ 4,650 $ 3,512
========= ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $38,614,0001,888 $2,515
======= ======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $10,203,000 and
$13,877,000 and for income taxes was $8,581,000 and $3,164,000 in 2002 and
$42,627,000 and for income taxes was $5,524,000 and $16,040,000 in 2001, and
2000,
respectively.
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD--------------------------------------------------------
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses:WTU is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in west and central Texas. WTU
sells electric power at wholesale which consiststo other utilities, municipalities, rural
electric cooperatives and beginning in 2002 to retail electric providers (REPs)
in Texas (see "Introduction of generation, retail electricity sales,Customer Choice" section below).
Wholesale power marketing and trading activities are conducted on WTU's
behalf by AEPSC. WTU, along with the other AEP electric operating subsidiaries,
shares in AEP's forward trades with other utility systems and power marketers.
Introduction of electricity;Customer Choice
On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas. WTU currently
operates in both the ERCOT and energy delivery which consistsSPP (Southwest Power Pool) regions of Texas, with
the majority of its operations being in the ERCOT territory.
Under the Texas Restructuring Legislation, each electric utility has
been required to submit a plan to structurally unbundle its business into a
retail electric provider, a power generator, and a transmission and distribution
services. Sinceutility. During the mergeryear 2000, WTU submitted a plan for separation that was
subsequently approved by the PUCT. As a result of this legislation, WTU has
functionally separated its generation from its transmission and distribution
operations and formed a separate REP. Pending regulatory approval, WTU will
corporately separate its generation from its transmission and distribution
operations. The REP is a separate legal entity that is a subsidiary of AEP and
CSW in June 2000, we
participateis not owned by or consolidated with WTU. Since the REP is the electricity
supplier to retail customers in the ERCOT area, WTU sells its generation to the
REP and provides transmission and distribution services to retail customers in
its ERCOT service territory. As a result of the formation of the REP, WTU no
longer supplies electricity to retail customers in the ERCOT area. Instead WTU
sells its generation to the REP. The implementation of REPs as suppliers to
retail customers has caused a significant shift in WTU's sales as described
below under "Results of Operations."
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP System's powerengages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to WTU. Trading
activities allocated to WTU involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of open energy trading contracts.
Recording the net change in the fair value of open trading contracts
as revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. Under MTM accounting the change in the unrealized gain or loss
throughout a contract's term is recognized in each accounting period. When the
contract actually settles, that is, the energy is actually delivered in a sale
or received in a purchase or the parties agree to forego delivery and receipt of
electricity and net settle in cash, the unrealized cumulative gain or loss is
reversed out of revenues and the actual realized cash gain or loss is recognized
in revenues for a sale or in purchased power expense for a purchase. Therefore,
over the trading contract's term an unrealized gain or loss is recognized as the
contract's market value changes. When the contract settles the total gain or
loss is realized in cash but only the difference between the accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized. Unrealized mark-to-market gains and losses are included in the
Balance Sheet as energy trading contract assets or liabilities.
Our trading activities represent physical forward electricity contracts
that are typically settled by entering into offsetting contracts. An example of
our trading activities is when, in January, we enter into a forward sales
contract to deliver electricity in July. At the end of each month until the
contract settles in July, we would record our share of any difference between
the contract price and the market price as an unrealized gain or loss in
revenues. In July when the contract settles, we would realize our share of a
gain or loss in cash and reverse to revenues the previously recorded cumulative
unrealized gain or loss. Prior to settlement, the change in the fair value of
physical forward sale and purchase contracts is included in revenues on a net
basis. Upon settlement of a forward trading contract, the amount realized is
included in revenues for a sales contract and the realized cost is included in
purchased power expense for a purchase contract with the prior change in
unrealized fair value reversed in revenues.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match, then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts from this point forward will have no further impact on
results of operations but will have an offsetting and equal effect on trading
contract assets and liabilities. Of course we could also do similar transactions
but enter into a purchase contract prior to entering into a sales contract. If
the sale and purchase contracts do not match exactly as to volumes, delivery
point, schedule and other key terms, then there could be continuing
mark-to-market effects on revenues from recording additional changes in fair
values using mark-to-market accounting.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices at
settlement do not correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing WTU to market risk. See "Quantitative and
Qualitative Disclosures about Market Risk" section for a discussion of the
policies and procedures used to manage exposure to risk from trading activities.
Results of Operations
Net income increased $3.1 million or 348% for the thirdquarter. This increase
is due mostly to significant decreases in both average unit costs of fuel and
average costs of purchased power.
Overall operating revenues decreased $53.8 million for the quarter as
shown below:
Increase (Decrease)
(in millions) %
Electricity Marketing
and Trading* $(100.0) (66)
Energy Delivery* 2.0 5
Sales to AEP Affiliates 44.2 N.M.
----
Total $ (53.8) (28)
=======
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
N.M. = Not Meaningful
Electricity marketing and trading revenues decreased $100.0 million as a
result of several factors, including the elimination of retail sales in the
ERCOT as of January 1st, 2002, a decrease in energy trading, and a milder than
normal winter. Sales to AEP affiliates increased $3.4$44.2 million or
32%, due to increasesrevenues
to the newly-created affiliated REP.
Due mostly to a decrease in fuel expense and electricity marketing and
trading purchases, operating expenses declined $59.5 million. Changes in the
components of operating expenses are shown below:
Increase (Decrease)
(in millions) %
Fuel $(34.9) (58)
Electricity Marketing and
nonoperating income. Year-to-date
net incomeTrading Purchases (17.2) (28)
Purchases from AEP Affiliates (8.8) (43)
Other Operation (1.6) (6)
Maintenance (0.2) (5)
Depreciation and Amortization (0.2) (2)
Taxes Other Than Income Taxes 0.3 4
Income Taxes 3.1 N.M.
---
Total $(59.5) (31)
======
N.M. = Not Meaningful
Although there was only a slight decrease in the consumption of fuel,
fuel expense decreased $1.5 million, or 7%,significantly due mostly to a decrease in the average
unit cost of fuel as a result of lower spot market natural gas prices.
A milder than normal winter coupled with decreasing purchased power
prices lead to a decrease in both electricity marketing and trading purchases
and electricity purchases from AEP affiliates.
A decrease in other operation expense was the result of a decrease in
operating income offset by an increase in nonoperating income.
Nonoperating income increased in both periods as the result of loss
provisions that were recorded in the second and third quarters of 2000
for the termination of merchandise sales and the cost of phasing out of
the merchandising sales programs.ERCOT transmission-related fees.
Income statement line item which
changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $180 72 $344 73
Fuel Expense (16) (28) 15 11
Purchased Power Expense 204 198 329 235
Other Operation Expense (6) (20) 9 13
Maintenance Expense (1) (12) 1 8
Depreciation and Amortization (7) (29) (3) (6)
Taxes Other Than Federal Income Taxes 3 43 4 23
Federal Income Taxes 2 29 (3) (27)
Nonoperating Income 2 N.M. 6 N.M.
N.M. = Not Meaningful
The significant increase in revenues for the quarter resulted
from increased trading volumes of the wholesale business. In the
year-to-date period, the increase in revenues is primarily attributable
to our participation in AEP's power marketing and trading operations and
higher fuel related revenues due to increased fuel and purchased power
expense of the wholesale business.
Fuel expense decreased for the quarter and increased in the
year-to-date period. The fluctuation in spot market natural gas prices
resulted in a decrease for the quarter and an increase in the
year-to-date period.
The increase in purchased power expense was primarily
attributable to our participation in AEP's power marketing and trading
operation and the adverse impact of natural gas prices on wholesale
purchased power prices.
Other operation expense decreased for the quarter due
primarily to decreased transmission expenses. Other operation expense
increased year-to-date due to a favorable adjustment made in January 2000
related to a FERC-approved Transmission Coordination Agreement.
Maintenance expense increased due to the overhaul in 2001 of
the Oklaunion Power Plant of our wholesale business.
Depreciation and amortization expense decreased due to the
effect of recording additional accruals in the third quarter of 2000 for
estimated excess earnings as required by Texas Restructuring Legislation.
An increase in taxes other than federal income taxes resulted
from an increase in Texas franchise tax assessments and an increase in
the Texas PUCT benefit assessment tax, a new tax in the state of Texas.
Federal income taxes attributable to operations increased in
the quarter and decreased year-to-date, reflecting the fluctuationsdue to a significant
increase in pre-tax income in those periods.
The increaseincome.
A decrease in nonoperating income was duecaused by a decrease in
mark-to-market financial energy trading losses.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $ 50,365 $150,341
Energy Delivery 40,629 38,642
Sales to a loss
provision that was recorded in the secondAEP Affiliates 50,242 6,023
------ -----
Total Operating Revenues 141,236 195,006
------- -------
OPERATING EXPENSES:
Fuel 24,980 59,905
Purchased Power:
Electricity Marketing and third quarters of 2000 for
the termination of merchandise salesTrading 44,123 61,300
AEP Affiliates 11,650 20,392
Other Operation 24,170 25,756
Maintenance 4,356 4,562
Depreciation and the cost of phasing out of the
merchandising sales programs.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $429,623 $249,330 $817,468 $473,407
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 41,667 57,728 148,420 133,515
Purchased Power 306,931 102,825 469,108 140,173
Other Operation 25,636 32,046 76,747 68,101
Maintenance 4,379 4,959 15,987 14,866
Depreciation and Amortization 16,149 22,717 39,449 42,050
Taxes Other Than Federal Income Taxes 10,136 7,096 22,949 18,712
Federal Income Taxes 6,980 5,394 9,243 12,706
----- ----- ----- ------
TOTAL OPERATING EXPENSES 411,878 232,765 781,903 430,123
------- ------- ------- -------
OPERATING INCOME 17,745 16,565 35,565 43,284
NONOPERATING INCOME (LOSS) 1,628 (202) 2,506 (3,441)
----- ---- ----- ------
INCOME BEFORE INTEREST CHARGES 19,373 16,363 38,071 39,843
INTEREST CHARGES 5,306 5,693 16,980 17,270
----- ----- ------ ------
NET INCOME 14,067 10,670 21,091 22,573
PREFERRED STOCK DIVIDEND REQUIREMENTS
26 26 78 78
-- -- -- --
EARNINGS APPLICABLE TO COMMON STOCK
$ 14,041 $ 10,644 $ 21,013 $ 22,495
========= ======== ========= ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $115,148 $116,093 $122,588 $113,242
NET INCOME 14,067 10,670 21,091 22,573
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 7,206 4,500 21,618 13,500
Preferred Stock 26 26 78 78
-- -- -- --
BALANCE AT END OF PERIOD $121,983 $122,237 $121,983 $122,237
======== ========Amortization 11,569 11,771
Taxes Other Than Income Taxes 6,300 6,038
Income Taxes (Credit) 2,943 (110)
----- ----
Total Operating Expenses 130,091 189,614
------- -------
OPERATING INCOME 11,145 5,392
NONOPERATING INCOME (LOSS) (1,488) 2,045
NONOPERATING EXPENSES 1,372 332
NONOPERATING INCOME TAX EXPENSE (CREDIT) (989) 282
INTEREST CHARGES 5,282 5,932
----- -----
NET INCOME 3,992 891
PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26
-- --
EARNINGS APPLICABLE TO COMMON STOCK $3,966 $ 865
====== =====
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $105,970 $122,588
NET INCOME 3,992 891
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 6,749 7,206
Preferred Stock 26 26
-- --
BALANCE AT END OF PERIOD $103,187 $116,247
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2001 December 31, 2000
------------------ -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 439,825 $ 431,793
Transmission 249,976 235,303
Distribution 428,473 416,587
General 113,827 110,832
Construction Work in Progress 21,106 34,824
------ ------
Total Electric Utility Plant 1,253,207 1,229,339
Accumulated Depreciation and Amortization 539,587 515,041
------- -------
NET ELECTRIC UTILITY PLANT 713,620 714,298
------- -------
OTHER PROPERTY AND INVESTMENTS 24,516 23,154
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 28,683 20,944
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 6,328 6,941
Accounts Receivable:
Customers 20,340 36,217
Affiliated Companies 9,570 16,095
Allowance for Uncollectible Accounts (163) (288)
Fuel Inventory - at average cost 9,969 12,174
Materials and Supplies - at average cost 11,314 10,510
Under-recovered Fuel 53,863 68,107
Energy Trading Contracts 104,458 152,174
Prepayments and Other Current Assets 1,306 851
----- ---
TOTAL CURRENT ASSETS 216,985 302,781
------- -------
REGULATORY ASSETS 16,849 24,808
------ ------
DEFERRED CHARGES 7,128 2,947
----- -----
TOTAL ASSETS $1,007,781 $1,088,932
========== ==========WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 442,078 $ 443,508
Transmission 253,347 250,023
Distribution 437,265 431,969
General 108,580 112,797
Construction Work in Progress 18,749 22,575
------ ------
Total Electric Utility Plant 1,260,019 1,260,872
Accumulated Depreciation and Amortization 547,380 546,162
------- -------
NET ELECTRIC UTILITY PLANT 712,639 714,710
------- -------
OTHER PROPERTY AND INVESTMENTS 25,634 24,933
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 14,120 21,532
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 556 2,454
Accounts Receivable:
Customers 30,945 18,720
Affiliated Companies 24,928 8,656
Allowance for Uncollectible Accounts (237) (196)
Fuel - at average cost 8,977 8,307
Materials and Supplies - at average cost 11,426 11,190
Under-recovered Fuel Costs 33,419 32,791
Energy Trading Contracts 25,383 63,252
Prepayments and Other Current Assets 453 966
--- ---
TOTAL CURRENT ASSETS 135,850 146,140
------- -------
REGULATORY ASSETS 11,786 13,659
------ ------
DEFERRED CHARGES 15,358 2,446
------ -----
TOTAL ASSETS $915,387 $923,420
======== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2001 December 31, 2000
------------------ -----------------
(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 2,236 2,236
Retained Earnings 121,983 122,588
------- -------
Total Common Shareowner's Equity 261,433 262,038
Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,482 2,482
Long-term Debt 255,936 255,843
------- -------
TOTAL CAPITZALIZATION 519,851 520,363
------- -------
CURRENT LIABILITIES:
Advances from Affiliates 46,130 58,578
Accounts Payable - General 21,356 45,562
Accounts Payable - Affiliated Companies 14,992 42,212
Customer Deposits 3,221 2,659
Taxes Accrued 46,009 18,901
Interest Accrued 4,319 3,717
Energy Trading Contracts 104,489 154,919
Other 10,614 7,906
------ -----
TOTAL CURRENT LIABILITIES 251,130 334,454
------- -------
DEFERRED INCOME TAXES 148,872 157,038
------- -------
DEFERRED INVESTMENT TAX CREDITS 23,099 24,052
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 28,957 20,789
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 35,872 32,236
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,007,781 $1,088,932
========== ==========WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(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 2,236 2,236
Retained Earnings 103,187 105,970
------- -------
Total Common Shareowner's Equity 242,637 245,420
Cumulative Preferred Stock Not Subject to
Mandatory Redemption 2,482 2,482
Long-term Debt 220,998 220,967
------- -------
TOTAL CAPITZALIZATION 466,117 468,869
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 35,000 35,000
Advances from Affiliates 89,168 50,448
Accounts Payable - General 17,958 33,782
Accounts Payable - Affiliated Companies 26,263 11,388
Customer Deposits - 4,191
Taxes Accrued 21,563 17,358
Interest Accrued 2,832 1,244
Energy Trading Contracts 21,843 65,414
Other 13,875 12,001
------ ------
TOTAL CURRENT LIABILITIES 228,502 230,826
------- -------
DEFERRED INCOME TAXES 145,078 145,049
------- -------
DEFERRED INVESTMENT TAX CREDITS 22,463 22,781
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 12,183 18,455
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 41,044 37,440
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $915,387 $923,420
======== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
NineThree Months Ended September 30,March 31,
2002 2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 21,0913,992 $ 22,573891
Adjustments for Noncash Items:
Depreciation and Amortization 39,449 42,05011,569 11,771
Deferred Income Taxes (8,060) 5,586(226) 85
Deferred Investment Tax Credits (953) (953)(318) (318)
Mark-to-Market of Energy Trading Contracts (664) (2,129)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 22,277 (89)(28,456) 12,381
Fuel, Materials and Supplies 1,401 6,469(906) (1,051)
Accounts Payable (51,426) 16,369(949) (15,986)
Taxes Accrued 27,108 1,292
Transmission Coordination Agreement Settlement - 15,4654,205 5,044
Fuel Recovery (628) (1,843)
Deferred Property Taxes (4,297) -
Fuel Recovery 14,245 (34,310)(9,525) (8,616)
Change in Other (net) 1,634 (588)Assets (4,118) 3,049
Change in Other Liabilities (288) 2,281
---- ----- ----
Net Cash Flows From (Used For) Operating Activities 62,469 73,864
------ ------(26,312) 5,559
------- -----
INVESTING ACTIVITIES:
Construction Expenditures (28,811) (43,938)(7,531) (10,762)
Other (127)- -
---- -------------
Net Cash Flows Used For Investing Activities (28,938) (43,938)
-------(7,531) (10,762)
------ -------
FINANCING ACTIVITIES:
Retirement of Long-term Debt - (40,000)
Change in Advances from Affiliates (net) (12,448) 26,23838,720 9,238
Dividends Paid on Common Stock (21,618) (13,500)(6,749) (7,206)
Dividends Paid on Cumulative Preferred Stock (78) (78)(26) (26)
--- ---
Net Cash Flows Used ForFrom (Used For) Financing Activities (34,144) (27,340)
------- -------31,945 2,006
------ -----
Net Increase (Decrease)Decrease in Cash and Cash Equivalents (613) 2,586(1,898) (3,197)
Cash and Cash Equivalents at Beginning of Period 2,454 6,941 6,074
----- -----
Cash and Cash Equivalents at End of Period $ 6,328556 $ 8,660
======== ========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $11,761,0003,744
===== =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $2,097,000 and
$2,162,000 and for income taxes was ($1,575,000) and ($2,957,000) in 2002 and
$13,994,000 and for income taxes was ($2,957,000) and $5,442,000 in
2001, and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
NOTES TO FINANCIAL STATEMENTS
SEPTEMBER 30, 2001NOTES TO FINANCIAL STATEMENTS
MARCH 31, 2002
(UNAUDITED)
The notes to financial statements are a combined presentation for AEP and its
subsidiary registrants as follows:
Note Registrant that Note applies to
---- -------------------------------
1. General AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
2. Extraordinary ItemsGoodwill and Cumulative Effect
of Accounting ChangeOther
Intangible Assets AEP CSPCo, OPCo
3. Acquisitions and
Sales
of AssetsDispositions AEP OPCo, SWEPCo
4. Rate Matters AEP, CPL, SWEPCo, WTU
5. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO, SWEPCo, WTU
6. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
7. Financing and Related
Activities and Minority Interest AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo WTU
8. Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 20002001 Annual Report as incorporated in and filed
with the Form 10-K.
The AEP System operating companies have reclassified certain
settled forward energy transactions of their trading operation from a
net to a gross basis of presentation in order to better reflect the
scope and nature of the AEP System's energy sales and purchases. All
financially net settled trading transactions, such as swaps, futures,
and unexercised options, continue to be reported on a net basis,
reflecting theCertain prior period financial nature of these transactions. The following
prior year amountsstatement items were reclassified
from revenues to purchased power
expenseconform to present the priorcurrent period presentation. Reclassifications had no
effect on a comparable basis:
Three Months Ended Nine Months Ended
September 30, 2000 September 30, 2000
Company (in thousands)
-------
AEP $7,692,103 $15,756,630
APCo 1,063,249 2,660,105
CPL 194,425 194,425
CSPCo 574,254 1,506,671
I&M 637,437 1,651,035
KPCo 252,596 631,748
OPCo 901,960 2,300,395
PSO 196,527 196,527
SWEPCo 196,449 196,449
WTU 48,139 48,139previously reported net income.
In the opinion of management, the unaudited 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. EXTRAORDINARY ITEMSGOODWILL AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE
OPCoOTHER INTANGIBLE ASSETS
SFAS 142, "Goodwill and CSPCo Recognize Extraordinary LossOther Intangible Assets" was effective
for AEP on January 1, 2002. The adoption of SFAS 142 requires the
transition testing for impairment of all indefinite lived intangibles
by the end of the first quarter and initial testing of goodwill by the
end of the second quarter of 2002. In the first quarter of 2002, AEP
completed testing the goodwill of its domestic operations and its
indefinite lived intangible assets and there was no impairment.
We recently began testing for goodwill impairment of our UK
operations as required by SFAS 142 and will complete the initial
testing in the second quarter of 2002. If after completing our
transition testing we determine that any goodwill is impaired, the
transitional impairment loss from the Stranding of Ohio
Gross Receipts Tax
OPCo and CSPCo recognized an extraordinary loss for stranded Ohio
Public Utility Excise Tax (commonly known as the Gross Receipts Tax -
GRT) net of allowable Ohio coal credits during the quarter ended June
30, 2001. This loss resulted from regulatory decisions in connection
with Ohio deregulation which stranded the recovery of the GRT. The
components of the extraordinary loss by company were:
CSPCo OPCo Total
----- ---- -----
(in thousands)
Gross Receipts Tax $42,493 $50,461 $92,954
Less Coal Credits 7,733 17,361 25,094
------- ------- -------
Net Liability for Ohio
Gross Receipts Tax 34,760 33,100 67,860
Less Income Tax Benefit 8,353 11,585 19,938
------- ------- -------
Extraordinary Loss $26,407 $21,515 $47,922
======= ======= =======
As discussed in Note 7 of the 2000 Annual Report, CSPCo and OPCo
appealed to the Ohio Supreme Court a PUCO order on Ohio restructuring
that the companies believe failed to provide for recovery for the final
year of the GRT. Effective May 1, 2001, the PUCO order reduced the
companies' rates by the annual level of GRT. Effective with the
liability affixing on May 1, 2001, the PUCO's decision to deny recovery
in the final year of the GRT resulted, under SFAS 101, in an
extraordinary impairment of the prepaid asset due to the deregulation of
the companies' generation business.
CSPCo and OPCo continue to seek recovery at the Ohio Supreme
Court where a decision is expected in 2002.
Cumulative Effect of Accounting Change - Affecting AEP
Guidance for certain fuel supply contracts with volume
optionality and electricity capacity contracts issued by the FASB's
Derivative Implementation Group (DIG) regarding the implementationadoption of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities"
became effective in the third quarter of 2001. The guidance concluded
that fuel supply contracts with volumetric optionality cannot qualify
for a normal purchase or sale exclusion from mark-to-market accounting
and provided guidance for determining when electricity capacity
contracts can qualify as a normal purchase or sale.
Predominantly all of AEP's contracts for coal, gas and
electricity, which are recorded on a settlement basis, do not meet the
criteria of a financial derivative instrument, qualify as a normal
purchase or sale, and are thereby exempt from the DIG guidance described
above. Beginning July 1, 2001, the effective date of the DIG guidance,
certain of AEP's fuel supply contracts with volumetric optionality that
qualify as financial derivative instruments are marked to market with
any gain or loss recognized in the income statement. The effect of
initially adopting the DIG guidance at July 1, 2001, a favorable
earnings mark-to-market effect of $18 million, net of tax, is142 will be
reported as a cumulative effect of an accounting change retroactive to
January 1, 2002.
Also see "Possible Divestitures" in Management's Discussion and
Analysis for related discussion of potential material losses.
SFAS 142 also changed the accounting and reporting for goodwill
and other intangible assets. Effective with the adoption of SFAS 142
on January 1, 2002 the amortization of goodwill ceased. SFAS 142
requires that other intangible assets be separately identified and if
they have finite lives, they must be amortized over that life.
New reporting requirements imposed by SFAS 142 include the
disclosures shown below.
Goodwill
The changes in the carrying amount of goodwill for the three
months ended March 31, 2002 by operating segment are:
Energy
Wholesale Delivery Other AEP Consolidated
(in millions)
Balance January 1, 2002 $340 $37 $1,169 $1,546
Goodwill acquired 2 - - 2
Goodwill assigned from
purchase price allocation
for recent prior period
acquisitions 77 - - 77
Non-transitional
impairment loss - - (12) (12)
Foreign currency exchange
rate changes - - (22) (22)
- - --- ---
Balance March 31, 2002 $419 $37 $1,135 $1,591
==== === ====== ======
In the first quarter of 2002, AEP recognized a goodwill
impairment loss of $12 million ($8 million net of tax) as a result of
management's decision to exit its Gas Power Systems business that was
developing customized generators powered by surplus helicopter engines.
Management elected to exit this business due to technical problems with
the underlying technology and recognized an impairment loss for all
goodwill related to the acquisition of Gas Power Systems.
As required by SFAS 142 the following tables show the
transitional disclosures to adjust reported net income statement.and earnings per
share to exclude amortization expense recognized in prior periods
related to goodwill and intangible assets that are no longer being
amortized and adjustments for changes in amortization periods for
intangible assets that continue to be amortized.
Net Income Three Months Ended March 31,
2002 2001
---- ----
(in millions)
Reported Net Income $181 $266
Add back: Goodwill amortization - 9
Add back amortization for intangibles with
indefinite lives under SFAS 142 - 2
-- -
Adjusted Net Income $181 $277
==== ====
Earnings Per Share (Basic and Dilutive) Three Months Ended March 31,
2002 2001
---- ----
Reported Earnings per Share $0.56 $0.83
Add back: Goodwill amortization - 0.03
Add back amortization for intangibles with
indefinite lives under SFAS 142 - -
--- ---
Adjusted Earnings per Share $0.56 $0.86
===== =====
Acquired Intangible Assets
Acquired intangible assets subject to amortization are $31
million at March 31, 2002 and $20 million at December 31, 2001 net of
accumulated amortization. The gross carrying amount and accumulated
amortization by major asset class are:
March 31, 2002 December 31, 2001
Gross Carrying Accumulated Gross Carrying Accumulated
Amount Amortization Amount Amortization
(in millions) (in millions)
CitiPower retail
supply licenses $25 $4 $24 $4
Unpatented Technology 10 - - -
-- - - -
Totals $35 $4 $24 $4
=== == === ==
Amortization of intangible assets was $0.5 million for the three
months ended March 31, 2002.
Estimated aggregate amortization expense is $2.2 million for
each year 2003 through 2008.
Acquired intangible assets no longer subject to amortization are
comprised of distribution licenses for CitiPower operating franchises
with a carrying amount of $440 million and $421 million at March 31,
2002 and December 31, 2001.
Fluctuations in the carrying values of the CitiPower retail
supply and distribution licenses since December 31, 2001 represent
changes in the foreign currency exchange rate.
3. ACQUISITIONS AND SALES OF ASSETS
SaleDISPOSITIONS
In January 2002 AEP acquired for $2 million the existing
trading operations, including 34 key staff, of Generating Assets - Affecting AEP
As discussedEnron's Norway and
Sweden-based energy trading businesses. The acquisition is an addition
to the growing energy trading operation in Note 3Europe based in the U.K.,
where we now trade power and gas in the U.K., France, Germany, and the
Netherlands and coal throughout the world. Results of operations are
included in the consolidated income statements from the acquisition
date. Based on a preliminary purchase price allocation the excess of
cost over fair value of the 2000 Annual Report, the divestiture
of 1,904 MW of generating capacity was required by the FERC and the PUCT
as part of the approval of the merger. In March 2001 AEP completed the
sale of Frontera, one of the generating plants required to be divested
under the settlement agreements approved by the FERC. The sale proceeds
were $265 million and resulted in an after tax gain of $46 million.
Acquisition of Houston Pipe Line Company - Affecting AEP
On June 1, 2001, AEP, through a wholly owned subsidiary,
purchased Houston Pipe Line Company and Lodisco LLC for $727 million.
The acquired assets include 4,200 miles of gas pipeline, a 30-year
sublease of a gas storage facility and certain gas marketing contracts.
The purchase method of accounting was used to record the acquisition.
AEP recorded thenet assets acquired and liabilities assumed based upon
their estimated fair values.is approximately $2
million which is recorded as goodwill. The allocation of the purchase
price may be
adjusted based uponis subject to revision after completion of thea final appraisal process. The purchase
method results in the assets and earnings of
the acquired operations
being included in AEP's consolidated financial statements from the
purchase date.
Acquisitionfair values of Lignite Mining Operations - Affecting AEP and SWEPCo
On June 1, 2001, SWEPCo assumed mining operations at its jointly
owned lignite reserves in Louisiana. To settle litigation, which is
discussed in Note 8, SWEPCo paid $86 million to purchase the mining
assets and rights of the previous mine operator and assumed existing
mine reclamation liabilities. The lignite from the mine will continue to
supply SWEPCo's jointly owned power plant. Management expects the
acquisition to have minimal impact on results of operations.
Sale of Generating Assets - Affecting AEP
In July 2001 AEP, through a wholly owned subsidiary, sold its 50%
interest in a 120-megawatt generating plant located in Mexico. The sale
resulted in a third quarter after tax gain of approximately $11 million.
Sale of Coal Mines - Affecting AEP and OPCo
In July 2001 AEP and OPCo sold coal mines in Ohio and West
Virginia and agreed to purchase approximately 34 million tons of coal
from the purchaser of the mines through 2008. The sale had a nominal
impact on results of operations.
Acquisition of Coal Assets - Affecting AEP
In October 2001 AEP acquired substantially all the assets of
Quaker Coal Company as part of a bankruptcy proceeding settlement. AEP
paid $101 million to Quaker's creditors and assumed additional
liabilities of approximately $45 million. The acquisition includes
property, coal reserves, mining operations and royalty interests in
Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. AEP will
continue to operate the mines and facilities which employ over 800
individuals. The purchase method of accounting was used to record the
acquisition. AEP recorded the assets acquired and liabilities assumed
based upon their estimatedassumed.
In April 2002 AEP reached a definitive agreement to transfer
two of its Texas retail electric providers (REPs) to Centrica, a
provider of retail energy and other consumer services. An independent
appraiser will establish a fair values. The allocationmarket value for the transaction after
mid-June 2002. This approach satisfies the parties<180> desire to have
the transfer price reflect the actual fair market value on a date
nearer to closing, and is consistent with the pooling of interests
accounting limitations imposed on AEP until June 15, 2002, in
connection with its merger with Central and South West Corp. If the
appraised value is outside the range of $133 million to $153 million,
the transaction need not be completed.
AEP will provide Centrica with a power supply contract for the
two REPs and all back-office services related to these customers for a
two-year period following closing. In addition, AEP retains the right
to share in earnings from the two REPs above a threshold amount through
2006 in the event the Texas retail market develops increased earnings
opportunities. AEP will also receive an up-front payment of
approximately $39 million from Centrica associated with the back-office
service agreement. Completion of the purchase
price may be adjusted basedtransaction is contingent upon completion of anthe
fair market value appraisal process. The
purchase method results inmeeting the assets and earnings of the acquired
operations being included in AEP's consolidated financial statementsrequired contractual
guidelines, regulatory approval from the purchase date.
AcquisitionPUCT and federal anti-trust
clearance. AEP and Centrica expect to complete the regulatory approval
process and conclude the transaction by the end of Barge Line - Affecting AEP
On November 1, 2001, AEP, through a wholly owned subsidiary,
acquired MEMCO Barge Line. The $270 million acquisition adds 1200 hopper
barges and 30 towboats to AEP's existing barging fleet. MEMCO's 450
employees will continue to operate the barge line. The purchase method
of accounting was used to record the acquisition. AEP recorded the
assets acquired and liabilities assumed based upon their estimated fair
values. The allocation of the purchase price may be adjusted based upon
completion of an appraisal process. The purchase method results in the
assets and earnings of the acquired operations being included in AEP's
consolidated financial statements from the purchase date.2002.
4. RATE MATTERS
As discussed in Note 5 of the Notes to Financial Statements in the
2001 Annual Report, certain WTU wholesale customers filed a complaint with
FERC alleging that WTU had overcharged them through the fuel adjustment
clause for certain purchased power costs since 1997. The customers allege
WTU had billed them for not only the cost of a 1999 Oklaunion outage, but
also certain additional costs that are not permissible under the fuel
adjustment clause.
Negotiations to settle the complaint and update the contracts are
continuing. In March 2002 WTU recorded a provision for refund of $2.2
million before income taxes. The actual refund and final resolution of
this matter could differ materially from this estimate and may have a
negative impact on future results of operations, cash flow and financial
condition.
Texas Fuel CostsRetail Price-to-Beat Rates - Affecting AEP
The Texas retail electric providers (REP) for the ERCOT area, CPL
REP and WTU REP, filed with the PUCT to increase the fuel portion of their
"price-to-beat" rate. The Texas legislation provides for the adjustment of
the fuel portion of the rate up to twice annually based on changes in the
market price of fuel using a natural gas price index. Any rate adjustment
approved by the PUCT would be effective on June 28, 2002 or a later date
ordered by the PUCT.
5. INDUSTRY RESTRUCTURING
As discussed in the 2001 Annual Report, customer choice began in
four of the eleven state retail jurisdictions in which the AEP domestic
electric utility companies operate. The following paragraphs discuss
significant events occurring in 2002 related to customer choice and
industry restructuring.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
As discussed in Note 7 of the Notes to Financial Statements in the
2001 Annual Report, CSPCo and OPCo filed an appeal with the Ohio Supreme
Court related to a tax expense issue which would result in duplicate
expense of $40 million and $50 million, respectively, for a twelve month
period beginning on May 1, 2001. On April 3, 2002, the Ohio Supreme
Court rejected the companies' arguments related to a duplicate tax
period and affirmed the PUCO's order which established the effective
date of tax credit riders in rates. This ruling had no impact on results
of operations as the companies had recorded an extraordinary loss when
the prepaid asset was stranded by a PUCO order in 2001.
Virginia Restructuring - Affecting AEP and APCo
On January 1, 2002, choice of electricity supplier for retail
customers began in Virginia. Presently, APCo continues to service
virtually all its previous customers. Per settlement agreements and
terms of the restructuring law, APCo's capped rates are the rates which
were in effect on July 1, 1999 and no wires charge will be collected
during 2002. See the 2001 Annual Report for further discussion.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
As discussed in Note 5 of the 20002001 Annual Report, AEP's Texas
electric operating companies experienced natural gas fuel price increases
which resulted in under-recoveries of fuel costs.
Fuel recovery for Texas utilities is a multi-step procedure. When
fuel costs change, utilities file with the PUCT for authority to adjust
fuel factors. If a utility's prior fuel factors result in an over- or
under-recovery of fuel, the utility will also request a surcharge factor
to refund or collect that amount. While fuel factors are intended to
recover all fuel-related costs, final settlement of these accounts are
subject to reconciliation and approval by the PUCT.
Fuel reconciliation proceedings determine whether fuel costs
incurred and collected during the reconciliation period were reasonable
and necessary. All fuel costs incurred since the prior reconciliation date
are subject to PUCT review and approval. If material amounts are
determined to be unreasonable and ordered to be refunded to customers,
results of operations and cash flows would be negatively impacted.
According to Texas Restructuring Legislation, fuel cost in the Texas
jurisdiction after 2001 will no longer be subject to PUCT review and
reconciliation. During 2002 CPL will file a final fuel reconciliation with
the PUCT to reconcile its fuel costs through the period ending December
31, 2001. The ultimate recovery of deferred fuel balances at December 31,
2001 will be decided as part of CPL's 2004 true-up proceeding. If the
final under-recovered fuel balances or any amounts incurred but not yet
reconciled are disallowed, it would have a negative impact on results of
operations.
In October 2001 the PUCT delayed the start of customer choice in the
SPP area of Texas. Portions of SWEPCo's and WTU's service territories are
in the SPP. The effect of the delay on fuel recovery is being reviewed by
the PUCT and management. The PUCT has not announced how the delay will be
applied to WTU whose customers are in SPP and ERCOT.
The following table lists the status of Texas jurisdictional
reconciliation, total fuel cost subject to reconciliation, under-recovered
fuel balances and the remaining fuel surcharge by company:
Fuel cost subject to Under-recovered
Reconciliation reconciliation at fuel balances at Remaining authorized
Company completed through September 30, 2001 September 30, 2001 fuel surcharge
------- ----------------- ------------------ ------------------ --------------
CPL June 30, 1998 $1.6 billion $11 million NONE
SWEPCo December 31, 1999 283 million 18 million $6 million
WTU June 30, 1997 641 million 51 million 3 million
Under Texas restructuring, newly organized retail electric providers
will make sales to consumers beginning in January 1, 2002. These sales
will be at fixed rates during a transition period from 2002, through 2006.
However, the fuel cost component of a retail electric providers' fixed
rates will be subject to prospective adjustment twice a year based upon
changes in a natural gas price index. As part of the preparation for
customer choice, CPL, SWEPCo and WTU filed their proposed fuel factors to
be implemented as part of the fixed rates effective January 1, 2002. The
filings are pending at the PUCT.
Status of Rate Filings
Central Power and Light
In January 2001 CPL filed an application with the PUCT to implement
a $175.9 million increase in fuel factors over the ten months March 2001
through December 2001. In addition, to collect its under-recovered fuel
costs, CPL proposed to implement an interim fuel surcharge of $51.8
million, which includes accumulated interest on unrecovered amounts. The
PUCT approved in April 2001 the implementation of a $170.5 million
increase in fixed fuel factors. The PUCT voted to defer implementation of
the requested fuel surcharge until the final fuel reconciliation, which
occurs as part of the 2004 true-up proceeding.
Southwestern Electric Power Company
In November 2000 SWEPCo filed with the PUCT to increase its fuel
factors effective January 2001 and to collect previously under-recovered
fuel costs over a six-month period through a proposed interim fuel
surcharge, which includes accumulated interest on previous unrecovered
fuel costs. The PUCT approved an increase in SWEPCo's fuel factors of $12
million and the implementation of a fuel surcharge of $11.8 million from
February to July 2001.
In May 2001 SWEPCo filed an application to increase its fuel factors
by $4.3 million. The application also proposed a fuel surcharge of $18.3
million, which includes accumulated interest on previous unrecovered fuel
costs. The PUCT approved in August 2001 a unanimous stipulation, requiring
SWEPCo to withdraw its fuel factors request and to implement a surcharge
of $10.7 million for unrecovered fuel. The PUCT deferred the remaining
$6.8 million balance of unrecovered fuel until a later proceeding.
West Texas Utilities
In April 2001 the PUCT approved new fuel factors for WTU to collect
$43.4 million of increased fuel costs from March through December 2001.
WTU implemented the increase in its fuel factors in March 2001 after an
Administrative Law Judge approved a settlement of WTU's application. WTU's
original application, in January 2001, had requested a $46.5 million
increase in its fuel factors.
In March 2001 WTU filed with the PUCT to implement a fuel surcharge
for under-recovered fuel costs of $59.5 million including interest on
previous unrecovered fuel costs. WTU requested that the surcharge be
effective May 2001 through December 2001. In October 2001 the PUCT
deferred consideration of WTU's fuel recovery until the 2004 true-up
proceeding.
Texas Transmission Rates - Affecting AEP, CPL and WTU
On June 28, 2001, the Supreme Court of Texas ruled that the
transmission pricing mechanism created by the PUCT in 1996 was invalid.
The court upheld an appeal filed by unaffiliated Texas utilities that the
PUCT exceeded its statutory authority to set such rates for the period
January 1, 1997 through August 31, 1999. Effective September 1, 1999, the
legislature granted this authority to the PUCT. CPL and WTU were not
parties to the case. However, the companies' transmission sales and
purchases were priced using the invalid rates. It is unclear what action
the PUCT will take to respond to the court's ruling. If the PUCT changes
rates retroactively, the result could have a material impact on results of
operations and cash flows for CPL and WTU.
FERC Transmission Rates - Affecting AEP, CPL, PSO, SWEPCo and WTU
In November 2001 FERC issued an order requiring CPL, PSO, SWEPCo and
WTU to submit revised open access transmission tariffs, and calculate and
issue refunds for overcharges from January 1, 1997. The order resulted
from a remand by an appeals court of a tariff compliance filing order
issued in November 1998 that had been appealed by certain customers. The
companies are evaluating the order and its impact on results of operations
and cash flows.
Excess Earnings - Affecting AEP, CPL, SWEPCo and WTU
In March 2001 CPL, SWEPCo and WTU filed their Annual Report of
Excess Earnings for 2000 with the PUCT. In July 2001 the companies
received notice that the Staff of the PUCT and the Office of Public
Utility Counsel (OPC) disagreed with the reports as filed. The Staff and
OPC took exception to certain adjustments made by the companies. OPC also
took exception to the application of certain sections of the law as it
pertains to the calculation of revenue within the report.
The PUCT issued a final order in September 2001 and the companies
recorded adjustments to match estimated provisions with final amounts.
The companies requested a rehearing on the proper determination of
excess earnings which the PUCT denied. In October 2001 the companies filed
in district court seeking judicial review of the PUCT's determination of
excess earnings. A decision from the court is not expected until 2002.
5. INDUSTRY RESTRUCTURING
----------------------
As discussed in the 2000 Annual Report, restructuring legislation
has been enacted in seven of AEP's eleven state retail electric
jurisdictions. The legislation provides for a transition from cost-based
regulation of bundled electric service to customer choice and market
pricing for the generation of electricity.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Effective January 1, 2001,
customer choice of electricity supplier began underin the Ohio Act. The PUCOERCOT area of
Texas. Customer choice has been delayed in other areas of Texas
including the SPP area. All of SWEPCo's Texas service territory and a
small portion of WTU's service territory are located in the SPP area.
CPL operates entirely in the ERCOT area of Texas.
Under the Texas Legislation, the PUCT approved alternative suppliers (many of
whom remain inactive) to compete for CSPCo's and OPCo's customers.
Virtually all customers continue to be served by CSPCo and OPCo.
In accordance with the Ohio Act, CSPCo and OPCo implemented rate
reductions of 5%business
separation plans for the utility companies. The business separation
plans provided for CPL and WTU to establish separate companies and
divide their integrated utility operations and assets into a power
generation portioncompany, a transmission and distribution utility and a retail
electric provider.
Due to the delay in the start of residential rates effective
January 1, 2001. The generation portion of retail rates, including fuel,
will remain frozen until December 31, 2005 orcompetition in the PUCO determines that a
competitive market exists.
On January 16, 2001, Shell Energy Services Company filed a Notice of
Appeal with the Ohio Supreme Court challenging PUCO's approval of our
transition settlement agreement including recoverySPP area and
lack of regulatory assets.
Shell withdrew as an alternativeapproval for our corporate separation plan, only
CPL's and WTU's retail supplier for Ohio. The PUCO's
motion to dismiss Shell's appeal is pending before the Ohio Supreme Court.
Management is unable to predict the outcome of this litigation. The
resolution of this matter could negatively impact future results ofelectric providers commenced operations and cash flows.
Virginia Restructuring - Affecting AEP and APCo
In accordance with its restructuring law, the Virginia jurisdiction
will begin a transition to choice of electricity supplier for retail
customers on
January 1, 2002. The Virginia restructuring law requires
filings to be made that outline the functional separation of generation
from transmission and distribution and a rate unbundling plan. APCo filed
its separation plan and rate unbundling plan with the Virginia SCC.
Hearings were held in October 2001. Settlement agreements that resolved
most issues except the assignment of the generation - related regulatory
assets among functionally separated generation and delivery organizations
are pending before the Virginia SCC. Presently, capped rates are
sufficient to recover generation - related regulatory assets. Management
is unable to predict the outcome of the hearings.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 Arkansas enacted legislation to restructure its electric
utility industry. In February 2001 the Arkansas General Assembly passed
legislation that was signed into law by the Governor to delay
restructuring. The legislation extended the dateOperations for the start of retail
electric competition to October 1, 2003 and provided the Arkansas
Commission with the authority to delay that date for up to two additional
years.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU have been
functionally separated. The companies anticipate completing legal
separation following receipt of the appropriate regulatory approvals.
In February 2002 CPL through a subsidiary issued $797 million of
transition notes approved under the securization clauses in the Texas
Restructuring Legislation gives customers the opportunity to
chooseLegislation. The transition notes provide more economical
financing for certain transition generation related regulatory assets
during their electric provider and eliminates the fuel clause
reconciliation process beginning January 1, 2002.recovery period.
A 2004 true-up proceeding will determine the amount of total
stranded costs, if any, including the final fuel recovery, net
regulatory asset recovery, certain environmental costs, accumulated
excess earnings offsets and other issues. As discussedThe Texas Legislation allows
for several alternative methods to be used to value stranded costs in
the 2000 Annual Report,final 2004 true-up proceeding including the method usedsale of and/or exchange
of generation assets, the issuance of power generation company stock to
determine
initialthe public or the use of an ECOM model. To the extent that the final
2004 true-up proceeding determines that CPL should recover additional
stranded costs, tothe additional amount recoverable can also be
recovered beginning on January 1, 2002 is
still subject to challenge. In March 2000 CPL submitted a $1.1 billion
estimate of stranded costs. After hearings on the submission, thesecuritized.
The PUCT issued in February 2001 an interim decision determining an initial amount
of stranded costs for CPL of negative $580 million. In April 2001 the PUCT
ruled that its current estimate of CPL's stranded costs was negative $615
million. CPL disagrees with the ruling and has requested a rehearing.
In April 2001 the PUCT issued an order requiringordered CPL to reduce distribution rates by $54.8
million over a five-year period beginning January 1, 2002 in order to
return estimated excess earnings for 1999, 2000 and 2001. The Texas
Restructuring Legislation intended that excess earnings would be used to
reduce stranded costs.cost. Final stranded cost amounts and the treatment of
excess earnings will be determined in the 2004 true-up proceeding. Currently theThe
PUCT currently estimates that CPL will have no stranded costscost and has
ordered the rate reduction to return excess earnings.
Management believes that CPL will have stranded costs inearnings, pending the
outcome of the 2004 and that
the current treatment of excess earnings will be amended at that time.true-up proceeding. Since CPL expensed excess
earnings amounts in 1999, 2000, and 2001, the April order has no additional
effect on reported net income. The amount to
be refunded is recorded as a regulatory liability.
As discussed in Note 7 of the 2000 Annual Report, the PUCT
authorized the issuance of up to $797 million of bonds to securitize
certain of CPL's regulatory assets. The PUCT's order that authorized the
securization was appealed to the Supreme Court of Texas. On June 6, 2001,
the Supreme Court upheld the PUCT's securitization order. The Court
dismissed the plaintiffs' request for a rehearing. Management plans to
issue the securitization bonds prior to January 1, 2002.
On August 3, 2001, the Staff of the PUCT filed a Petition seeking a
determination of whether electric operations in the SPP are ready for
competition. This Petition affects parts of SWEPCo and WTU. Under the
Texas Restructuring Legislation, the PUCT can delay the start of
competition if the market and its participants are not prepared for
competition. Under the law, certain situations indicate this lack of
preparedness, and in Staff's opinion, those indicators are presentincome but will reduce cash flows for the SPP area. In October 2001 the PUCT ordered a delay in the start of retail
competition in the SPP area of Texas and continued the pilot project in
the SPP area. Management is evaluating the ramifications of this delay in
thefive
year refund period.
Beginning January 1, 2002, start date of competitionfuel costs for SWEPCo'sCPL and WTU's Texas
operationsWTU in the SPP.
A Texas settlement agreement in connectionERCOT
are no longer subject to PUCT fuel reconciliation proceedings.
Consequently, CPL and WTU will file a final fuel reconciliation with the
AEP and CSW
merger permits CPL to apply up to $20 million of previously identified STP
ECOM plant assets a year in 2000 and 2001 to reduce any excess earnings.
STP ECOM plant assetsPUCT which reconciles their fuel costs through the period ending
December 31, 2001. These final fuel balances will be depreciatedincluded in accordance with GAAP, on a
systematiceach
company's 2004 true-up proceeding. The elimination of the fuel clause
recoveries in 2002 in Texas will subject AEP, CPL and rational basis. ToWTU to the extent excess earnings exceed $20
million in 2001, CPL will establish a regulatory liability by a charge to
earnings.risk of
fuel market price increases and could adversely affect results of
operations.
In the event CPL, SWEPCo, and WTU 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 and other restructuring related costs, it could result in an extraordinary loss which could have a
material adverse effect on results of operations, cash flows and
possibly financial condition.
Michigan Restructuring - Affecting AEP and I&M
As discussed in the 2000 Annual Report, the Michigan Legislation
gave the MPSC broad powers to implement customer choice. In compliance
with MPSC orders, on June 5, 2001, I&M filed its proposed unbundled rates,
open access tariffs and terms of service. On October 11, 2001, the MPSC
issued an "Order Approving Settlement Agreement" which generally approved
I&M's June 5, 2001 filing except for agreed upon modifications. In
accordance with the settlement agreement, I&M agreed that recovery of
implementation costs and regulatory assets would be determined in future
proceedings. The settlement agreement did not modify the procedure for
review of decommissioning cost recoveries. Customer choice commencescommenced for I&M's Michigan customers on
January 1, 2002. Effective with that date the rates on I&M's Michigan
customers' bills for retail electric service were unbundled to allow
customers the opportunity to evaluate the cost of generation service for
comparison with other offers. I&M's total rates in Michigan remain
unchanged and reflect cost of service. At this time, none of I&M's
customers have elected to change suppliers and no competing suppliers
are active in I&M's Michigan service territory.
Management does not expecthas concluded that as of March 31, 2002 the
requirements to apply SFAS 71 continue to be met since I&M's rates for
generation in Michigan continue to be cost-based regulated. As a result
I&M will incur material tangible
asset impairments orhas not yet discontinued regulatory asset write-offs. If I&M is not permitted
to recover all or a portion of its generation-related regulatory assets,
unrecorded decommissioning obligation, stranded costs or other
implementation costs in future proceedings, it could result in an
extraordinary loss that could have a material adverse effect on results of
operations, cash flows and possibly financial condition.
Oklahoma Restructuring - Affecting AEP and PSO
In June 2001 the Oklahoma Governor signed into law a bill that
delayed retail electric competition indefinitely. Under previously
approved legislation, the start date for Oklahoma customer choice had been
July 1, 2002.accounting under SFAS 71.
6. BUSINESS SEGMENTS
AEP'sAEP has three principal business segments: Wholesale, Energy Delivery and
Other. The business activities of each of these segments and their respective
activities are:
oare as follows:
Wholesale
o Generation of electricity for sale to retail and wholesale customers,
o Marketing and trading of electricity and gas worldwide,worldwide.
o Gas pipeline and storage services and other energy supply related
businesses.business
o Coal mining, bulk commodity barging operations and other energy
supply related businesses
Energy Delivery
o Domestic electricelectricity transmission
o Domestic electric distribution.
oelectricity distribution
Other Investments
o Foreign electricity generation investments,
o Foreign electric distribution and supply investments
o Telecommunication services.
Amounts reported belowservices
Segment results of operations for the three months ended March
31, 2002 and 2001 are shown below. These amounts include certain
estimates and allocations where necessary.
We have used Earnings before Interest and Income Taxes (EBIT)
as a measure of segment operating performance. The EBIT measure is total
operating revenues net of total operating expenses and other income and
deductions from income. It differs from net income in that it does not
take into account interest expense or income taxes. EBIT is believed to
be a reasonable gauge of results of operations. By excluding interest
and income taxes, EBIT does not give guidance regarding the demand of
debt service or other interest requirements, or tax liabilities or
taxation rates. The effects of interest expense and taxes on overall
corporate performance can be seen in the consolidated statements of
income.
The amounts shown for the three business segments reported by AEP
include certain estimates and allocations where necessary.
Energy Other Reconciling
Wholesale Delivery Investments Adjustments Consolidated
March 31, 2002 (in millions)
Nine months ended September 30, 2001 (in millions) Revenues from:
External customers $36,219$12,115 $ 2,599 $5,041798 $ 3,219 $47,078
Transactions with other501 $ - $13,414
Other operating segments 1,771 14 789 (2,574)658 1 243 (902) -
Segment EBIT 1,387 810 201 (121) 2,277238 204 65 - 507
Total assets at September 30,34,248 12,958 6,096 (3,149) (a) 50,153
(a) Reconciling adjustments for Total Assets:
Eliminate intercompany balances (3,855)
Corporate assets 706
------
(3,149)
March 31, 2001 32,632 13,321 8,008 (1,142) 52,819
Nine months ended September 30, 2000 Revenues from:
External customers 21,908 2,428 1,550 (24) 25,862
Transactions with other12,878 789 568 - 14,235
Other operating segments 1,214 1 503 (1,718) -192 (192)
Segment EBIT 779 872 261 (244) 1,668352 245 113 (5) 705
Total assets at September 30, 2000 23,574 11,918 5,306 (105) 40,69325,392 13,405 8,113 46,910
All of the registrant subsidiaries except AEGCo have two business
segments. The segment results for each of these subsidiaries are
reported in the table below. AEGCo has one segment, a wholesale
generation business. AEGCo's results of operations are reported in
AEGCo's financial statements.
NineThree Months Ended September 30, 2001 NineThree Months Ended
September 30,March 31, 2002 March 31, 2001 September 30, 2000 September 30, 2000
------------------ ------------------ ------------------
Revenues Revenues
From From
External Segment External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
--------- ---- --------- ----Wholesale Segment (in thousands) (in thousands)
WholesaleAPCo $1,300,161 $58,987 $3,103,614 $1,822,030 $62,766 $3,684,595
CPL 291,096 39,546 2,921,932 493,082 52,080 2,945,850
CSPCo 846,767 54,615 2,194,995 1,026,577 60,163 2,624,371
I&M 964,222 4,747 3,585,106 1,213,601 39,733 4,172,159
KPCo 316,179 5,757 656,456 422,830 1,021 840,123
OPCo 1,241,826 100,473 3,451,859 1,567,816 69,236 4,193,940
PSO 196,118 1,063 838,987 307,722 713 845,308
SWEPCo 261,813 9,637 1,142,945 347,632 17,220 1,146,835
WTU 100,607 5,818 392,701 156,364 (2,546) 442,070
Revenues Revenues
From From
External Segment APCo $5,385,003 $135,288 $3,066,057 $3,595,000 $ 119,458 $2,658,933
CPL 2,103,562 245,947 3,080,135 1,169,787 216,115 2,887,340
CSPCo 3,173,388 197,304 2,157,522 2,222,019 186,255 1,840,981
I&M 3,712,009 121,130 3,528,300 2,548,819 (124,079) 3,258,113
KPCo 1,282,741 4,516 638,684 841,129 10,171 540,291
OPCo 4,741,282 198,107 3,337,773 3,622,605 248,336 3,088,916
PSO 1,455,850 51,063 946,654 729,999 59,411 856,661
SWEPCo 1,626,283 73,034 1,304,534 782,780 33,247 1,130,548
WTU 682,956 12,410 432,338 332,458 8,548 393,230External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
Energy Delivery Segment (in thousands) (in thousands)
APCo $455,587 $165,744 $2,418,839 $425,792 $155,580 $2,097,656$154,995 $58,694 $2,448,468 $152,097 $63,189 $2,906,810
CPL 384,290 120,376 2,212,194 380,246 129,952 2,073,726112,127 26,527 2,098,569 110,330 32,372 2,072,634
CSPCo 358,984 81,452 1,213,606 300,455 69,692 1,035,552102,548 11,688 1,234,685 98,996 14,762 1,333,956
I&M 241,581 91,305 1,592,600 231,691 103,294 1,470,64374,537 35,321 1,618,241 77,937 36,114 1,704,121
KPCo 101,367 42,748 618,567 92,281 40,484 523,27435,129 16,500 635,780 36,327 16,636 701,388
OPCo 405,352 78,516 1,861,251 346,225 109,428 1,722,479141,760 23,943 1,924,868 131,849 34,077 2,019,304
PSO 208,911 75,360 1,054,728 195,739 80,581 954,46151,732 5,263 934,769 48,417 6,344 945,599
SWEPCo 262,943 97,149 1,357,780 271,276 118,874 1,176,69268,935 13,633 1,189,595 78,057 24,660 1,058,616
WTU 134,512 38,174 575,443 137,949 41,765 523,39140,629 5,408 522,686 38,642 9,540 486,649
Revenues Revenues
From From
Registrant Subsidiaries External Total Assets External
Company Total Customers EBIT Customers EBIT Total Assets
(in thousands) (in thousands)
APCo $5,840,590 $301,032 $5,484,896 $4,020,792 $275,038 $4,756,589$1,455,156 $117,681 $5,552,082 $1,974,127 $125,955 $6,591,405
CPL 2,487,852 366,323 5,292,329 1,550,033 346,067 4,961,066403,223 66,073 5,020,501 603,412 84,452 5,018,484
CSPCo 3,532,372 278,756 3,371,128 2,522,474 255,947 2,876,533949,315 66,303 3,429,680 1,125,573 74,925 3,958,327
I&M 3,953,590 212,435 5,120,900 2,780,510 (20,785) 4,728,7561,038,759 40,068 5,203,347 1,291,538 75,847 5,876,280
KPCo 1,384,108 47,264 1,257,251 933,410 50,655 1,063,565351,308 22,257 1,292,236 459,157 17,657 1,541,511
OPCo 5,146,634 276,623 5,199,024 3,968,830 357,764 4,811,3951,383,586 124,416 5,376,727 1,699,665 103,313 6,213,244
PSO 1,664,761 126,423 2,001,382 925,738 139,992 1,811,122247,850 6,326 1,773,756 356,139 7,057 1,790,907
SWEPCo 1,889,226 170,183 2,662,314 1,054,056 152,121 2,307,240330,748 23,270 2,332,540 425,689 41,880 2,205,451
WTU 817,468 50,584 1,007,781 470,407 50,313 916,621141,236 11,226 915,387 195,006 6,994 928,719
Management's intention is to structurally and functionally
separate operations into regulated and non-regulated businesses. The
vertically integrated generation-transmission-distribution operations
of the utility companies in Ohio and Texas (CSPCo, OPCo, CPL and WTU)
will be structurally separated into non-regulated wholesale and
regulated energy delivery businesses. The remaining utility
subsidiaries will to be grouped with AEP's regulated business.
Management is currently in the process of obtaining the necessary
regulatory approvals to implement this new business structure.
7. FINANCING AND RELATED ACTIVITIES
AND MINORITY INTEREST
Long-termIn the first quarter of 2002, CPL Transition Funding LLC, a
subsidiary of CPL, issued $797 million of transition notes under the
provisions of the Texas Restructuring Legislation (See Note 5). The
proceeds were used to reduce CPL's debt and other securities issuancesretire 4.5 million shares of
CPL's common stock. The notes were issued under the following classes:
Principal Interest Scheduled Final Final
Class Amount Rate Payment Date Maturity Date
----- --------- -------- --------------- -------------
(in millions) (%)
A-1 129 3.54 2005 2007
A-2 154 5.01 2008 2010
A-3 107 5.56 2010 2012
A-4 215 5.96 2013 2015
A-5 192 6.25 2016 2017
A subsidiary of AEP also increased borrowing on its revolving
credit agreement by $73 million. The agreement has a variable interest
rate and is due in 2003.
The following table lists long-term debt retirements during the
first nine monthsquarter of 2001 were:2002 by the registrant subsidiaries:
Principal
Type PrincipalAmount Interest Due
Company of Debt AmountRetired Rate Due Date
------- ------- -------------------- -------- --------
Issuances----
(in millions) (%)
---------
AEPCPL Senior Unsecured Notes $ 250 5.50(a) 2003
AEP$150 Variable 2002
SWEPCo Senior Unsecured Notes 1,000 6.125(a) 2006
APCo Senior Unsecured Notes 125 (b) 2003150 Variable 2002
Non-Registrant AEP Subs. Various 171 Various 2001-2004
------
Total AEP System $1,546
======
Retirements
APCo First Mortgage Bonds $ 100 6-3/8 2001
APCo Senior Unsecured Notes 75 4.00-6.00 2001
CPL Trust Preferred Securities 12 8.00 2037
CSP First Mortgage Bonds 42 7.25 2002
CSP First Mortgage Bonds 14 7.15 2002
CSP First Mortgage Bonds 32 6.80 2003
CSP First Mortgage Bonds 15 6.60 2003
CSP First Mortgage Bonds 15 6.10 2003
CSP First Mortgage Bonds 24 6.55 2004
CSP First Mortgage Bonds 24 6.75 2004
CSP First Mortgage Bonds 33 8.70 2022
CSP First Mortgage Bonds 23 8.40 2022
CSP First Mortgage Bonds 20 7.45 2024
CSP First Mortgage Bonds 21 7.60 2024
CSP Junior Debentures 2 8-3/8 2025
CSP Senior Unsecured Notes 12 6.85 2005
I&M First Mortgage Bonds 40 7.63 2001
I&M First Mortgage Bonds 5 7.35 2023
KPCo First Mortgage Bonds 20 8.95 2001
KPCo First Mortgage Bonds 40 8.90 2001
OPCo Senior Unsecured Notes 75 4.00-6.00 2001
OPCo Notes Payable 30 6.20 2001
OPCo Finance Obligation 13 6.98 2001
OPCo First Mortgage Bonds 13 6.00 2003
OPCo First Mortgage Bonds 30 6.15 2003
OPCo First Mortgage Bonds 45 8.80 2022
OPCo First Mortgage Bonds 10 7.75 2023
PSO First Mortgage Bonds 6 5.91 2001
PSO First Mortgage Bonds 5 6.02 2001
PSO First Mortgage Bonds 9 6.02 2001
Non-Registrant
AEP Subs. Various 230 Various 2001
------
Total AEP System $1,035
======12 Variable 2002-2007
----
$312
In addition to the transactions reported in the table above, the
following table lists intercompany issuances of debt and retirements
of debt due to AEP Co., Inc.
Interest
Company Type of Debt Principal Amount Rate Due Date
------- ------------ ---------------- ---- --------
Issuances (in millions) (%)
---------
CSP Notes Payable $ 200 (c) 2002
KPCo Notes Payable 60 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 575 4.336-6.501 2001-2006
------
Total AEP System $1,150
======
Retirements
-----------
Non-Registrant
AEP Subsidiaries Notes Payable $50 4.336-6.501 2001-2006
===
(a) In May 2001, AEP issued $1.25 billion of debt consisting of $1
billion of senior notes and $250 million of putable callable
notes. The interest rate on senior notes (due May 2006) is
6.125%. Additionally, AEP entered into an interest rate swap for
a portion of the proceeds, which effectively converts a portion
of this interest rate into LIBOR based floating rate through
2006. The putable callable notes (Series B notes) have a fixed
interest rate of 5.5% until May 2003. At that date the Series B
notes may be subject to call by a third party for purchase and
remarketing, in which case the maturity would extend until may
2013. If the Series B notes are not called for remarketing, they
will be redeemed.
(b) A floating interest rate is determined quarterly. The rate on
September 30, 2001 was 3.29%.
(c) A floating interest rate is determined quarterly. The rate on
September 30, 2001 was 3.265%.
Other Financing Activities
On May 24, 2001, AEP renewed its existing $2.5 billion 364-day
revolving credit facility. AEP renews this facility annually and uses
it, together with an existing $1 billion 5-year revolving credit which
matures May 30, 2005 as an alternative means of funding for AEP's
commercial paper program.
On May 30, 2001, AEP Credit ceased to issue commercial paper and
allowed its $2 billion unsecured revolving credit facility to mature. A
$1.5 billion 364-day note purchase agreement, which closed on May 30,
2001, replaced Credit's funding needs. Bank-sponsored financings are
funding this facility.
Minority Interest in Subsidiaries
AEP's minority interests at September 30, 2001 and 2000 include the
following:
2001 2000
---- ----
(in millions)
Funding Subsidiary $750 $ -
Nanyang General Light Electric Co. 20 17
Other 3 3
---- ---
$773 $20
==== ===
In August 2001 AEP formed a funding subsidiary as a limited
liability company and sold a non-controlling, preferred interest in
such limited liability company to a third party for $750 million. The
preferred interest receives a preferred return equal to an adjusted
floating reference rate. The $750 million received replaces interim
funding used to acquire Houston Pipe Line Company in June 2001(see Note
3). The preferred interest is supported by pipeline assets and $325
million of a preferred stock interest in an AEP affiliate which is
convertible, under certain circumstances, into $325 million of AEP
common stock. AEP could elect not to have the transaction supported by
the preferred stock of its affiliate if the preferred interest were
reduced by $225 million. The results of operations, cash flows and
financial position of the limited liability company are consolidated
with AEP. The non-controlling preferred interest in the limited
liability company is included on AEP's consolidated balance sheet line
"Minority Interest in Subsidiaries."
8. CONTINGENCIES
Litigation
Shareholders' Litigation - Affecting AEP
In 2000 five complaints were filed against AEP seeking
unspecified compensatory damages for alleged violations of federal
securities laws. A court order consolidated the cases. However, the
court has not determined if the plaintiffs represent a class consisting
of all persons and entities who acquired AEP common stock between July
25, 1997 and June 25, 1999. On March 5, 2001, AEP filed a motion to
dismiss the cases. All parties presented oral arguments on AEP's motion
to dismiss on June 7, 2001. Management believes these shareholder
complaints are without merit and intends to continue to oppose them. The
outcome of this litigation or its impact on results of operations, cash
flows or financial condition cannot be predicted.
Municipal Franchise Fee Litigation - Affecting AEP and CPL
CPL has been involved in litigation regarding municipal franchise
fees in Texas as a result of a class action suit filed by the City of
San Juan, Texas in 1996. The City of San Juan claims CPL underpaid
municipal franchise fees and seeks damages of up to $300 million plus
attorney's fees. CPL filed a counterclaim for overpayment of franchise
fees.
The litigation moved procedurally through the Texas Court System
and was sent to mediation without resolution. CPL notified the other
cities it serves of the pending class action suit. CPL has pledged to
extend any final decision which determines an underpayment of franchise
fees to cities who declined to participate in the suit. The court ruled
that the class of plaintiffs would consist of approximately 30 cities
and set a trial date.
During the third quarter of 2001 the cities who declined to
participate in the class action lawsuit reached an agreement with CPL to
settle their claims. The agreement with approximately 95 cities requires
CPL to pay a total of $8 million and releases CPL from any further
liability. CPL recorded the liability in August 2001.
In October 2001 CPL settled with the city of San Juan and the
remaining class action cities for approximately $3 million. Management
believes the court will approve the settlements and payments will be
made before year-end.
Texas Base Rate Litigation - Affecting AEP and CPL
As discussed in the 2000 Annual Report, CPL has been involved in
litigation concerning a 1997 PUCT base rate order.
The primary issues were:
o Classification of $800 million of invested capital at STP as
excess cost over market (ECOM) earning a lower return than
other generating property; and
o Disallowance of $18 million of affiliated service billings.
In October 2001 the Texas Supreme Court denied our request to
review this case. At this time, management is reviewing its options
which includes seeking a rehearing. Management is unable to predict the
final resolution of this litigation or its impact on results of
operations or cash flows.
Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo
In May 2001 SWEPCo settled ongoing litigation concerning lignite
mining in Louisiana. As discussed in Note 8 of the 2000 Annual Report,
SWEPCo has been involved in litigation concerning the mining of lignite
from jointly owned lignite reserves. SWEPCo and CLECO are joint owners
of Dolet Hills Power Station Unit 1 and own lignite reserves in the
Dolet Hills area of northwestern Louisiana. In 1982 SWEPCo and CLECO
entered into a lignite mining agreement with DHMV, a partnership for the
mining and delivery of lignite from these reserves. Since 1997 SWEPCo
and CLECO have been involved in litigation with DHMV and its partners.
In 2000 the parties agreed to settle the litigation. As part of the
settlement, SWEPCo purchased DHMV's interest in the mining assets and
mining rights for $86 million and assumed the related obligations for
mine reclamation (See Note 3). The settlement agreement gives CLECO the
option to acquire up to a 50% interest in the mining assets.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo,
CSPCo, I&M, and OPCo
As discussed in Note 8 of the 2000Notes to Financial Statements in
the 2001 Annual Report, AEP, 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
that AEP, APCo, CSPCo, I&M, OPCo and OPCo modified certaineleven unaffiliated utilities made
modifications to generating units at coal-fired generating plants in
violation of the Clean Air Act. The Federal EPA filed complaints against the companiesAEP
subsidiaries in U.S. District Court for the Southern District of Ohio in 1999.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
March 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.
In February 2001 the plaintiffsgovernment filed a motion requesting a
determination that four projects undertaken on units at Sporn, Cardinal
and Clinch River plants do not constitute "routine maintenance, repair
and replacement" as used in the Clean Air Act. The Circuit Court
denieddismissed the
plaintiffs' motion as premature.pre-mature. 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.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 withby 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 AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo
and SWEPCo
Federal EPA issued a rule (the NOx Rule)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.
The NOx Rule requiresrequired states to submit plans to comply with its
provisions. In 2000 Federal EPA ruled that eleven states, including
states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's
generating units are located, failed to submit approvable compliance
plans. Those states could face stringent sanctions including limits on
construction of new sources of air emissions, loss of federal highway
funding and possible Federal EPA takeoverassumption of state air quality
management programs. AEP subsidiaries and other utilities requested that
the D.C. Circuit Court review this ruling.
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 AEP's
coal-fired generating units. After review,Affected utilities including certain AEP
operating companies, petitioned the D.C. Circuit Court upheldto review the
Section 126 Rule.
TheAfter 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. OnIn August 24, 2001 the
D.C. Circuit Court issued an order tolling the compliance schedule until
Federal EPA responds to the Court's remand. TheOn 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 2000 the Texas Natural Resource Conservation Commission
adopted rules requiring significant reductions in NOx emissions from
utility sources, including those owned by CPL and SWEPCo. The compliance date is May
2003 for CPL and May 2005 for SWEPCo.
In May 2001AEP is installing selective catalytic reduction (SCR) technology
to reduce NOx emissionsemission. During 2001 SCR on OPCo's Gavin Plant began operation. Constructioncommenced
operations. Installation of SCR technology on Amos Plant Unit 3, which is jointly owned by OPCo
and APCo, and APCo's Mountaineer Plant began in 2001. The Amos and Mountaineer
projects (expected to beplants was completed and commenced operation in 2002) are estimated to
cost a total of $230 million ($145 million for APCo and $85 million for
OPCo).May 2002. Construction
of SCR technology on KPCo's Big Sandy Plant Unit 2
isat certain other AEP generating units continues with
completion scheduled for completion in May 2003 at an estimated cost of $107
million.
Preliminarythrough 2006.
Our estimates indicate that AEP's compliance for the AEP System with the NOx Rule,
the Texas Natural Resource Conservation Commission rule and the Section
126 Rule could result in required capital expenditures totalingof approximately
$1.6 billion.billion, including amounts spent through March 31, 2002. Estimated
compliance costs by registrant subsidiaries are as follows:
Estimated
Compliance Costs
----------------
(in millions)
AEGCo $125
APCo 365
CPL 57
CSPCo 106
I&M 202
KPCo 140
OPCo 606
SWEPCo 28
Since compliance costs cannot be estimated with certainty, the
actual cost to comply could be significantly different than the
preliminary
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 - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
At the date of Enron's bankruptcy 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.
In connection with the acquisition of HPL, we acquired from BAM
Lease Company, a now-bankrupt subsidiary of Enron, the right to use
under a 30-year lease, with a renewal right for another 20 years, the
Bammel gas storage facility. The lease includes the use of the Bammel
storage reservoir and the related above ground compression, treating and
delivery systems. We also entered into a "right to use" agreement with
BAM Lease Company which allows us to use approximately 55 billion cubic
feet of cushion gas (or pad gas) required for the normal operation of
the facility. The Bammel Trust which is the nominal owner of the cushion
gas has entered into a financing arrangement with a group of banks which
purports to provide rights to the cushion gas in certain circumstances.
The banks consented to our use of the cushion gas coextensive for the
term of the lease of the Bammel gas storage facility. We have been
informed by the banks of Bammel Trust's default under the terms of their
financing agreement and it is not clear what, if any, rights the banks
will assert with respect to the cushion gas.
In the fourth quarter of 2001 AEP provided $47 million ($31
million net of tax) for our estimated loss from the Enron bankruptcy.
The amounts for certain subsidiary registrants were:
Amounts
Amounts Net of
Registrant Provided Tax
-------- ---
(in millions)
APCo $5.2 $3.4
CSPCo 3.2 2.1
I&M 3.4 2.2
KPCo 1.3 0.8
OPCo 4.3 2.8
The amounts provided were based on an analysis of contracts where
AEP and Enron are counterparties, the offsetting of receivables and
payables, the application of deposits from Enron and management's
analysis of the HPL related purchase contingencies and indemnifications.
If there are any adverse unforeseen developments in the
bankruptcy proceeding or in Bammel Trust's default under the cushion gas
financing agreement, our future results of operations, cash flows and
possibly financial condition could be adversely impacted.
California Energy Market Investigation by FERC - Affecting AEP
On February 13, 2002, the FERC issued an order directing its
Staff to conduct a fact-finding investigation into whether any entity,
including Enron Corp., manipulated short-term prices in electric energy
or natural gas markets in the West or otherwise exercised undue
influence over wholesale prices in the West, for the period January 1,
2000, forward. In April 2002, AEP furnished certain information to the
FERC in response to their related data request.
Pursuant to the FERC's February 13, 2002 order, on May 8, 2002,
the FERC issued further data requests, including requests for
admissions, with respect to certain trading strategies engaged in by
Enron Corp. and, allegedly, traders of other companies active in the
wholesale electricity and ancillary services markets in the West,
particularly California, during the years 2000 and 2001. This data
request was issued to AEP as part of a group of over 100 entities
designated by the FERC as all sellers of wholesale electricity and/or
ancillary services to the California Independent System Operator and/or
the California Power Exchange.
The May 8, 2002 FERC data request requires senior management to
conduct an investigation into our trading activities during 2000 and
2001 and to provide an affidavit as to whether we engaged in certain
trading practices that the FERC characterized in the data request as
being potentially manipulative. Senior management intends to fully
comply with the order by the May 22, 2002 response date.
Other
AEP and its subsidiary registrants continue to be involved in
certain other matters discussed in the 20002001 Annual Report.
REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS
This is our combined presentation of management's discussion and
analysis of financial condition, contingencies and other matters related tofor AEP and our subsidiary registrants.its
registrant subsidiaries. Management's discussion and analysis of results of
operations for AEP and each of its registrant subsidiaries for the three and nine month periodsquarter ended
September 30, 2001March 31, 2002 is presented with each registrants'their financial statements elsewhereearlier in this
document.
FINANCIAL CONDITION
The rating agencies have been conducting credit reviews of AEP and its
registrant subsidiaries as we prepare for corporate separation. As of April 30,
2002, the ratings of AEP's commercial paper, the registrant subsidiaries' first
mortgage bonds and the senior unsecured debt of AEP and its registrant
subsidiaries is unchanged from year end. However, on April 19, 2002, Moody's
Investors Service announced that AEP and five of its registrant subsidiaries
(CPL, CSPCo, OPCo, SWEPCo and WTU) had been placed on credit rating watch for
possible downgrade.
The review of the companies' debt position and credit rating is being
completed in anticipation of corporate separation. We are working with Moody's
and providing information to support AEP's current credit rating. If our credit
ratings are lowered, the interest rates we pay on borrowings will potentially
rise thereby increasing our interest expense unless we can reduce our
borrowings.
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,
minority interestpreferred 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 notereceivables purchase agreement, a term loan facility and twothree
revolving credit agreements.
At
September 30, 2001, approximately $1.4 billion was available for short-term
borrowings. To facilitate corporate separation, AEP issued $1.25 billion of
global notes in May 2001 (with intermediate maturities). The proceeds may be
loaned to certain subsidiaries, primarily in Ohio and Texas, to allow them to
reacquire debt with covenants that limit asset transfer or sale. Corporate
separation will require the transfer of assets between legal entities.
During the first nine monthsquarter of 20012002 cash flow from operations of $1.2
billion, the proceeds of the $1.25 billion global notes issuancewas negative
$14 million, including $181 million from net income and proceeds$290 million from
depreciation, amortization and deferred taxes. Capital expenditures including
acquisitions were $378 million and dividends on common stock were $193 million.
Cash from the saleissuance of a UK distribution company and two generating plants$797 million of transition funding bonds provided
cashfunds to purchase HPL until permanent funding was arranged,cover the operating funds deficiency, reduce debt, fund construction
retire debt
and pay dividends. Major construction expenditures included amounts for a wind generation plant and emission
control technology on several coal-fired generating units (see discussion in
Note 8).
During the thirdfourth quarter of 2001, HPL's permanent financing was completed by an issuance of a minority
interest which provided $735 million net of expenses. HPL's permanent financing
will increase funds available for other corporate purposes.
During the fourth quarter, Quaker Coal Co. and, MEMCO Barge Line,
Inc. and two coal-fired generating plants in the UK were acquired using
short-term borrowings and available cash. In October 2001,
we announced our intent to acquire two coal-firedLong-term financing arrangements are
being negotiated for the UK generating plants in the UK.
The transaction is expected to be completed by the end of the year. Long-term
financing for these three acquisitionsand will be arranged and announced as
completed. Completion of this financing is anticipated in the second quarter of
2002. Long-term funding arrangements are often complex and can not be
completed immediately.take time to
complete.
As discussed in the annual report, we filed with the SEC in April 2002
for authorization to issue a combination of up to $3 billion in equity or debt
to improve our financial condition as measured by our debt to equity ratio. We
currently anticipate an equity offering between $1 billion and $1.5 billion.
This issuance proposes to include AEP common stock and other equity or
convertible debt instruments.
Total consolidated plant and property additions including capital leases
for the year-to-datefirst quarter period were $1.3 billion.$354 million. The following table shows the
plant and property additions by certain subsidiary registrants:registrant subsidiaries:
Company Amount
------- ------
(in millions)
APCo $188$63
CPL 15921
I&M 27
OPCo 66
OPCo 244
SWEPCo 7712
Possible Divestitures
We have a strong commitment to continually evaluate the need to
reallocate resources to areas that effectively match investments with our
strategy, provide greater potential for meaningful financial returns, and to
dispose of investments that do not meet these principles.
In particular, we have recently entered into a definitive agreement to
dispose of two of our Texas retail electric providers which serve retail
residential and small commercial customers in Texas. The disposal price will not
be determined until a date closer to the consummation of the transaction, which
is expected to be during the fourth quarter of 2002.
Other investments and assets being evaluated for potential disposition
include:
o SEEBOARD and CitiPower, our energy delivery and retail supply
businesses in the UK and Australia. In connection with our evaluations,
we have retained investment advisors and are assessing the relative
interests of several strategic and financial buyers of these
operations.
At SEEBOARD, we have provided interested parties an information
memorandum and, based upon their initial level of interest, have
provided some of those parties the opportunity to pursue more detailed
due diligence procedures. We expect to receive offers from these
parties to purchase SEEBOARD that are capable of acceptance late in the
second quarter. At CitiPower, we have distributed an information
memorandum and expect to receive similar offers late in June.
o our power generation interests in Medway Power in the UK, Nanyang
Electric in China, Pacific Hydro in Australia, and certain cogeneration
facilities in the US, our joint investment in power distribution in
Brazil, and our domestic telecommunications assets.
A recommendation, if one is proposed by management, to dispose of any
of these investments will be subject to the approval and authority of our Board
of Directors. The ultimate timing of a recommendation to our Board for a
disposition of one or more of these assets will depend upon market conditions
and the value of any buyer's proposal to us. If, based on the outcome of our
evaluations, our recommendation to and approval of our Board, we choose to
dispose of these assets, we would expect to realize non-recurring losses in the
aggregate that will have a material impact on our results of operations.
Corporate Separation
On July 24,As discussed in the 2001 Annual Report, we have filed an application with the FERC requestingand
SEC seeking approval of transactions necessary to complete a restructuring ofseparate our regulated and unregulated operations. These transactions will enable us to implement our
plansOur
plan for corporate separation and allowallows us to meet the requirements of Texas and
Ohio restructuring legislation. As part of the filed plan, AEP intendsWe intend to transfer the generation assets from
the integrated electric operating companies in Ohio and Texas (CSPCo, OPCo, CPL
and WTU) to unregulated generation companies. The filed plan also proposesWe proposed amendments ofto the
power pooling agreements for all operating companies. Only those operating
companies that continue to exist as integrated utilities would be included in
the amended power pooling agreements, which would govern energy exchanges among
members and the allocation of their off system purchases and sales. Several
state commissions, wholesale customer groups and other interested parties
intervened in the FERC proceeding. We have negotiated settlement agreements with
the intervenors. The settlement agreements have been filed at the FERC for
review and approval. FERC and SEC approval of our corporate separation plan is
required for its implementation. In order to execute this separation, we maywill be
required to retire various debt securities of CSPCo, OPCo, CPL and WTU.
In September 2001 CSPCo reacquired $263 million first mortgage bonds
and OPCo reacquired $97.5 million of first mortgage bonds in open market
transactions. CSPCo and OPCo used funds borrowed from AEP to reacquire the
bonds. First mortgage bond retirements will lower the amount of debt funded
under mortgage indenture covenants. The lower mortgage debt should facilitate
transfer of assets from one subsidiary to another.between legal
entities.
RTO Formation
As discussed in Note 3 of the 20002001 Annual Report, FERC Order No. 2000 and many of
the settlement agreements with the state regulatory commissions to approve the
AEP-CSW Mergermerger required the transfer of control of our transmission system to an
RTO. Certain AEP subsidiaries are participatingparticipated in the formation of the Alliance RTO, otherRTO.
Other subsidiaries are membermembers of ERCOT or the SPP.
Subsidiaries who are members of the SPP are evaluating their options for RTO
membership following the SPP's announcement of its intention to merge with the
MISO.
In 2001 the Alliance companies and MISO entered into a settlement
addressing transmission pricing and other "seams" issues between the two RTOs.
The FERC also has expressed its opinion that four large RTO regions serving the
continental USRTOs will better support
competition and reliability of electric service. FERC is re-evaluatingIn May 2002 AEP announced an
agreement with the functions that shouldPJM Interconnection to pursue terms for participation in its
RTO. Final agreements are expected to be exercised by RTOs,
as expressed in Order No. 2000, and has formed federal/state panels to examine
the issue. It has extended the December 15, 2001 deadline set forth in Order No.
2000 for RTOs to become operational, and has stated that it will substitute a
new timeline. Certain state regulatory commissions have taken exception to the
FERC's actions. Louisiana's commission ordered utilities it regulates, including
SWEPCo, to file to show the advantage of large RTOs to their customers.negotiated.
Management is unable to predict the outcome of these activitiestransmission
regulatory actions and proceedings or their impact on the timing and operation
of RTOs, our transmission operations or our results of operations and cash flows.
OTHER MATTERS
Industry Restructuring
As discussed in Note 5 and our 2000the 2001 Annual Report, sevenrestructuring and
customer choice began in four of ourthe eleven state retail jurisdictions enacted restructuring legislation. Thein which
the AEP electric utility companies operate. Restructuring legislation provides
for a transition from cost-based regulation of bundled electric service to
unbundled generation and energy delivery functions with customer choice and market pricing for the supply of electricity. Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Effective January 1, 2001, customerCustomer
choice of electricity supplier began under the Ohio Act. The PUCO approved alternative suppliers (many of whom
remain inactive) to compete for CSPCo's and OPCo's customers. CSPCo and OPCo
continue to serve virtually all customers.
In accordance with the Ohio Act, CSPCo and OPCo implemented rate
reductions of 5% for the generation portion of residential rates effective
January 1, 2001. Retail rates, including fuel, will remain frozen until December
31, 2005 or the PUCO determines that a competitive market exists.
An alternative supplier (who has since withdrawn from Ohio competition)
filed a Notice of Appeal with the Ohio Supreme Court challenging PUCO's approval
of our transition settlement agreement including recovery of regulatory assets.
A PUCO motion to dismiss this appeal is pending before the Ohio Supreme Court.
Management is unable to predict the outcome of this litigation. The resolution
of this matter could negatively impact our future results of operations and cash
flows. Virginia Restructuring - Affecting AEP and APCo
In accordance with its restructuring law, the Virginia jurisdiction
will begin a transition to choice of electricity supplier for retail customers
on January 1, 2002. The Virginia restructuring law requires filings to be made
that outline the functional separation of generation from transmission2001 for Ohio customers and
distribution and a rate unbundling plan. APCo filed its separation plan and rate
unbundling plan with the Virginia SCC. Hearings were held in October 2001.
Settlement agreements that resolved most issues except the assignment of the
generation - related regulatory assets among functionally separated generation
and delivery organizations are pending before the Virginia SCC. Presently,
capped rates are sufficient to recover generation - related regulatory assets.
We are unable to predict the outcome of the hearings.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 Arkansas enacted legislation to restructure its electric
utility industry. In 2001 legislation which extended the date for the start of
retail electric competition to October 1, 2003 and provided the Arkansas
Commission with the authority to delay that date for up to two additional years
became law.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
Texas Restructuring Legislation gives customers the opportunity to
choose their electric provider and eliminates the fuel clause reconciliation
process beginning January 1, 2002. A 2004 true-up proceeding will determine the
amount of stranded costs including the final fuel recovery, net regulatory asset
recovery, excess earnings offsets and other issues.
As discussed in our 2000 Annual Report, the method used to determine
initial stranded costs to be recovered beginning
on January 1, 2002, is still
subjectfor Michigan, Texas and Virginia customers. In Ohio,
Michigan and Virginia virtually all customers continue to challenge.receive electric
generation, transmission and distribution services from our electric operating
companies.
In March 2000 CPL submitted a $1.1 billion estimate of
stranded costs. After hearings on the submission,Texas jurisdiction competition began in the PUCT issuedERCOT area but was
delayed in February
2001 an interim decision determining an initial amount of stranded costs for CPL
of negative $580 million.the SPP area.
In April 2001 the PUCT ruled that its current estimate
of CPL's stranded costs was negative $615 million. We disagree with the ruling
and have requested a rehearing.
In April 2001 the PUCT issued an order requiring CPL to reduce itsfuture
distribution rates by $54.8 million for five-yearsover a five-year period beginning in January 1,
2002 in order to return estimated excess earnings for 1999, 2000 and 2001. The
Texas Restructuring Legislation intended that excess earnings would be used to
reduce stranded costs.cost. Final stranded cost amounts and the treatment of excess
earnings will be determined in the 2004 true-up proceeding. Currently theThe PUCT currently
estimates that CPL will have no stranded costscost and has ordered the rate reduction
to return excess earnings. We believe that CPL will have stranded costs inearnings, pending the outcome of the 2004 and that the
current treatment of excess earnings will be amended at that time. Sincetrue-up proceeding.
CPL expensed excess earnings amounts in 1999, 2000 and 2001,2001. Consequently, the
April order hadhas no
additional effect on reported net income.
The amount to be refunded is recorded
as a regulatory liability.
As discussed in Note 7 of our 2000 Annual Report, the PUCT authorized
the issuance of up to $797 million of bonds to securitize certain of CPL's
regulatory assets. The PUCT's order that authorized the securization was
appealed to the Supreme Court of Texas. On June 6, 2001, the Supreme Court
upheld the PUCT's securitization order. The Court dismissed the plaintiffs'
request for a rehearing. We plan to issue the securitization bonds in the near
term.
In October 2001, the PUCT delayed the start of retail competition in
the SPP area of Texas (see Note 5). We are evaluating the ramifications of this
delay in the
Beginning January 1, 2002, start date of competition for our SWEPCofuel costs are no longer subject to PUCT
fuel reconciliation proceedings under the Texas Restructuring Legislation.
Consequently, CPL and WTU Texas operations inwill file a final fuel reconciliation with the SPP.
A Texas settlement agreement in connection with our merger with CSW
permits CPLPUCT to
apply up to $20 million of previously identified STP ECOM plant
assets a year in 2000 and 2001 to reduce any excess earnings. STP ECOM plant
assetsreconcile their fuel costs through the period ending December 31, 2001. These
final fuel balances will be depreciatedincluded in accordance with GAAP, on a systematiceach company's 2004 true-up proceeding.
The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP,
CPL and rational
basis. ToWTU to the extent excess earnings exceed $20 millionrisk of fuel market price increases and could adversely
affect future results of operations beginning in 2001, CPL will
establish a regulatory liability by a charge to earnings.2002.
In the event CPL, SWEPCo, and WTU 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 and other restructuring
related costs, it could have a material adverse effect on results of operations,
cash flows and possibly financial condition. Michigan Restructuring - Affecting AEP and I&M
The Michigan Legislation gave the MPSC broad powers to implement
customer choice. We filed proposed unbundled rates, open access tariffs and
terms of service in June 2001. In October 2001 the MPSC approved a settlement
agreement related to our filing to implement customer choice on January 1, 2002.
We agreed that recovery of implementation costs and regulatory assets would be
determined in future proceedings and recovery of nuclear decommissioning costs
would continue to be reviewed separately.
We do not expect to incur material tangible asset impairments or
regulatory asset write-offs. If we are not permitted to recover all or a portion
of our generation-related regulatory assets, unrecorded decommissioning
obligation, stranded costs or other implementation costs in future proceedings,
it could have a material adverse effect on our results of operations, cash flows
and possibly financial condition.
Oklahoma Restructuring - Affecting AEP and PSO
In June 2001 the Oklahoma Governor signed into law a bill that delayed
retail electric competition indefinitely from its previously scheduled start
date of July 1, 2002.
Litigation
- ----------
Shareholders' Litigation - Affecting AEP
In 2000 five complaints were filed against us seeking unspecified
compensatory damages for alleged violations of federal securities laws (see Note
8). We believe these shareholder complaints are without merit and intend to
continue to oppose them. The outcome of this litigation or its impact on our
results of operations, cash flows or financial condition cannot be predicted.
Municipal Franchise Fee Litigation - Affecting AEP and CPL
In August and October 2001 CPL reached agreement to settle ongoing
litigation related to municipal franchise fees with 125 cities in its service
territory. The agreements require CPL to pay approximately $11 million. The
agreements are subject to approval by the court which management expects to
occur before year-end.
Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo
In May 2001 SWEPCo settled ongoing litigation concerning the mining of
lignite from reserves jointly owned with CLECO. As part of the settlement,
SWEPCo purchased the mine operator's interest in mining assets and mining rights
for $86 million and assumed the related obligations for mine reclamation (see
Note 3). The settlement agreement gives CLECO the option to acquire up to a 50%
interest in the mining assets. Federal EPA Complaint
and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo
As discussed in our 2000the 2001 Annual Report, and Note 8, Federal EPA, a number
of states and certain special interest groups alleged that AEP, APCo, CSPCo, I&M, and OPCo
modified certainhave 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 over a 20 year periodat 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. We
believe our maintenance, repair and replacement activities were in conformity
with the Clean Air Act and intend to vigorously pursue our defense.
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 March 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.
In February 2001 the government filed a motion requesting a
determination that four projects undertaken on units at Sporn, Cardinal and
Clinch River plants do not constitute "routine maintenance, repair and
replacement" as used in the Clean Air Act. The Circuit Court dismissed the
motion as premature. Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and intends to vigorously
pursue its defense.
If weManagement 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.
Ancondition 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 and abetween 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 AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and
SWEPCo
Federal EPA issued a rule (the NOx Rule) and granted petitions filed by
certain northeastern states (the Section 126 Rule)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 (see Note 8).located. The NOx Rule has been upheld on
appeal. The compliance date for the NOx Rule is May 31, 2004.
The NOx Rule required states to submit plans to comply with its
provisions. In 2000 Federal EPA ruled that eleven states, including states in
which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are
located, failed to submit approvable plans
to comply with the NOx Rule. This ruling means that thosecompliance plans. Those states could face
stringent sanctions including limits on construction of new sources of air
emissions, loss of federal highway funding and possible Federal EPA takeoverassumption
of state air quality management programs. A request forAEP subsidiaries and other utilities
requested that the D.C. Circuit Court review this ruling.
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 AEP's coal-fired generating units. Affected
utilities including certain AEP operating companies, petitioned the D.C. Circuit
Court to review this ruling is pending.
Thethe 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. In response to AEP subsidiaries and other utilities request forrequested
that the D.C. Circuit Court tovacate the Section 126 Rule or suspend theits May 2003
compliance date of the Section 126 Rule,date. In August 2001 the D.C. Circuit Court issued an order tolling
the compliance schedule until Federal EPA responds to the Court's remand. TheOn
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 2000 the Texas Natural Resource Conservation Commission adopted rules
requiring significant reductions in NOx emissions from utility sources,
including those owned by CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005
for SWEPCo.
In May 2001
AEP is installing selective catalytic reduction (SCR) technology to
reduce NOx emissionsemission. During 2001 SCR on OPCo's Gavin Plant began operation. Constructioncommenced operations.
Installation of SCR technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's
Mountaineer Plant began in 2001. The Amos and Mountaineer projects (expected to
beplants was completed and
commenced operation in 2002) are estimated to cost a total of $230 million ($145
million for APCo and $85 million for OPCo).May 2002. Construction of SCR technology on
KPCo's Big Sandy Plant Unit 2 isat certain other
AEP generating units continues with completion scheduled for completion in May 2003 at an
estimated cost of $107 million.
Preliminarythrough
2006.
Our estimates indicate that ourAEP's compliance with the NOx Rule, the
Texas Natural Resource Conservation Commission rule and the Section 126 Rule
could result in required capital expenditures totalingof approximately $1.6 billion.
billion,
including amounts spent through March 31, 2002.
The following table shows the estimated compliance cost for certain of
AEP's subsidiary registrants.registrant subsidiaries.
Company Amount
------- ------
(in millions)
APCo $365
CPL 57
I&M 202
OPCo 606
SWEPCo 28
Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the preliminary 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.
New Accounting Standards
The FASB recently issued SFAS 141, "Business Combinations"Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and SFAS 142,
"Goodwill And Other Intangible Assets." SFAS 141 requires thatOPCo
At the purchase
methoddate of accounting be used to account for all business combinations entered
into afterEnron's bankruptcy AEP had open trading contracts and
trading accounts receivables and payables with Enron. In addition, on June 30, 2001. SFAS 142 requires that goodwill1,
2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL
related contingencies and other intangible
assets with indefinite lives be tested for impairment upon SFAS 142
implementation and annually thereafter. Amortizationindemnities remained unsettled at the date of goodwill and other
intangible assets with indefinite lives will cease with our implementation of
SFAS 142 beginning January 1, 2002. The amortization of goodwill reduced our net
income $35 million for the nine months ended September 30, 2001. We have not
determined the impact of adopting the other provision of these standards.
SFAS 143, "Accounting for Asset Retirement Obligations," will become
effective for us beginning January 1, 2003. SFAS 143 establishes accounting and
reporting for obligations associatedEnron's
bankruptcy.
In connection with the retirementacquisition of tangible long-lived
assetsHPL, we acquired from BAM Lease
Company, a now-bankrupt subsidiary of Enron, the right to use under a 30-year
lease, with a renewal right for another 20 years, the Bammel gas storage
facility. The lease includes the use of the Bammel storage reservoir and the
related asset retirement costs.above ground compression, treating and delivery systems. We are currently evaluatingalso entered
into a "right to use" agreement with BAM Lease Company which allows us to use
approximately 55 billion cubic feet of cushion gas (or pad gas) required for the
provisionsnormal operation of the standardfacility. The Bammel Trust which is the nominal owner of
the cushion gas has entered into a financing arrangement with a group of banks
which purports to provide rights to the cushion gas in certain circumstances.
The banks consented to our use of the cushion gas coextensive for the term of
the lease of the Bammel gas storage facility. We have been informed by the banks
of Bammel Trust's default under the terms of their financing agreement and determining its impactit is
not clear what, if any, rights the banks will assert with respect to the cushion
gas.
In the fourth quarter of 2001 AEP provided $47 million ($31 million net
of tax) for our estimated loss from the Enron bankruptcy. The amounts for
certain subsidiary registrants were:
Amounts
Amounts Net of
Registrant Provided Tax
-------- ---
(in millions)
APCo $5.2 $3.4
CSPCo 3.2 2.1
I&M 3.4 2.2
KPCo 1.3 0.8
OPCo 4.3 2.8
The amounts provided were based on an analysis of contracts where AEP
and Enron are counterparties, the offsetting of receivables and payables, the
application of deposits from Enron and management's analysis of the HPL related
purchase contingencies and indemnifications.
If there are any adverse unforeseen developments in the bankruptcy
proceeding or in Bammel Trust's default under the cushion gas financing
agreement, our future results of operations, cash flows and possibly financial
condition and cash flows.
In August 2001could be adversely impacted.
California Energy Market Investigation by FERC - Affecting AEP
On February 13, 2002, the FASBFERC issued SFAS 144, "Accountingan order directing its Staff to
conduct a fact-finding investigation into whether any entity, including Enron
Corp., manipulated short-term prices in electric energy or natural gas markets
in the West or otherwise exercised undue influence over wholesale prices in the
West, for the Impairment
period January 1, 2000, forward. In April 2002, AEP furnished
certain information to the FERC in response to their related data request.
Pursuant to the FERC's February 13, 2002 order, on May 8, 2002, the FERC
issued further data requests, including requests for admissions, with respect to
certain trading strategies engaged in by Enron Corp. and, allegedly, traders of
other companies active in the wholesale electricity and ancillary services
markets in the West, particularly California, during the years 2000 and 2001.
This data request was issued to AEP as part of a group of over 100 entities
designated by the FERC as all sellers of wholesale electricity and/or Disposal of Long-lived Assets" which sets forthancillary
services to the accountingCalifornia Independent System Operator and/or the California
Power Exchange.
The May 8, 2002 FERC data request requires senior management to recognizeconduct
an investigation into our trading activities during 2000 and measure2001 and to provide
an impairment loss. This standard replacesaffidavit as to whether we engaged in certain trading practices that the previous standard,
SFAS 121, "Accounting forFERC
characterized in the Long-lived Assetsdata request as being potentially manipulative. Senior
management intends to fully comply with the order by the May 22, 2002 response
date.
Other
AEP and for Long-lived Assetsits subsidiary registrants continue to be Disposed Of." SFAS 144 will applyinvolved in certain
other matters discussed in the 2001 Annual Report.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU
As a major power producer and trader 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
uschanges in January 2002.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 Management
Committee and administered by a Chief Risk Officer. The Risk Management
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.
We douse a risk measurement model which calculates Value at Risk (VaR) to
measure our commodity price risk. The VaR is based on the variance - covariance
method using historical prices to estimate volatilities and correlations and
assuming a 95% confidence level and a one-day holding period. Based on this VaR
analysis, at March 31, 2002 a near term typical change in commodity prices is
not expected to have a material effect on our results of operations, cash flows
or financial condition. The following table shows the high, average, and low
market risk as measured by VaR at:
March 31, December 31,
2002 2001
---- ----
High Average Low High Average Low
(in millions) (in millions)
AEP $24 $16 $8 $28 $14 $5
APCo 4 2 1 4 1 -
CPL - - - 3 1 -
CSPCo 3 1 1 2 1 -
I&M 3 1 1 3 1 -
KPCo 1 1 - 1 - -
OPCo 4 2 1 3 1 -
PSO - - - 2 1 -
SWEPCo - - - 3 1 -
WTU - - - 1 1 -
We also utilize a VaR model to measure interest rate market risk
exposure. The interest rate VaR model is based on a Monte Carlo simulation with
a 95% confidence level and a one year holding period. The volatilities and
correlations were based on three years of weekly 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 $657 million at March
31, 2002 and $673 million at December 31, 2001. However, since we would not
expect the
implementation of SFAS 144 to liquidate our entire debt portfolio in a one year holding period, a
near term change in interest rates should not materially affect results of
operations or cash
flows.consolidated financial position.
AEGCo is not exposed to risk from changes in interest rates on
short-term and long-term borrowings used to finance operations since financing
costs are recovered through the unit power agreements.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ON RISK
RISK MANAGEMENT
AEP is exposed to risk from changes in the market prices of coal and
its registrant subsidiariesnatural 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 for CSPCo
and OPCo) and in the ERCOT area of Texas (effective January 1, 2002 for CPL and
WTU) or frozen by settlement agreements in Indiana, Michigan and West Virginia.
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 risksmarket price risk. AEP
continues to be protected against market price changes by active fuel clauses in
their day to
day operations. The risksOklahoma, Arkansas, Louisiana, Kentucky, Virginia and correlating strategies are:
Risk Description Strategy
- ---- ----------- --------
Market Risk Volatility in commodity prices Trading and hedging
Interest Rate Risk Changes in Interest rates Hedging
Foreign Exchange Risk Fluctuations in foreign currency rates Hedging
Credit Risk Non-performance on contracts with Guarantees, Collateral
counter parties
AEP's strategiesthe SPP area of trading, hedging and credit risk management to
mitigate various risks have not materially changed since
December 31, 2000.
Commodity Price RiskTexas.
We employ physical forward purchase and sale contracts, exchange futures
and options, over-the-counter options, swaps, and other derivative contracts to
offset marketprice risk where appropriate. However, we engage in trading of
electricity, gas and to a lesser degree coal, oil, natural gas liquids, and
emission allowances and as a result the Company is subject to price risk. AEP's internationally based electric distribution utilities
hedge marketThe
amount of risk through forward commodity contracts.
Interest Ratetaken by the traders is controlled by the management of the
trading operations and the Company's Chief Risk FairOfficer and his staff. When the
risk from trading activities exceeds certain pre-determined limits, the
positions are modified or hedged to reduce the risk to the limits unless
specifically approved by the Risk Management Committee.
We employ fair value andhedges, cash flow hedge contractshedges and swaps to mitigate
changes in interest rates or fair values on short and long-term debt of AEP, KPCo, and I&M. CitiPower useswhen
management deems it necessary. We do not hedge all interest rate swaps for the same purpose.
Foreign Exchange Risk
AEP, KPCo, and OPCorisk.
We employ cash flow forward hedge contracts to lock-in prices on
purchased assetstransactions denominated in foreign currencies.currencies where deemed necessary.
International subsidiaries use currency swaps to hedge exchange rate
fluctuations in debt transactions.denominated in foreign currencies. We do not hedge all
foreign currency exposure.
Credit Risk
AEP limits credit risk by accepting primarily investment grade counter
parties. Weextending unsecured credit to entities based
on internal ratings. In addition, 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. This data, in
conjunction with the ratings information, is used to determine appropriate risk
parameters. AEP also requirerequires cash deposits, letters of credit and
parental/affiliate guarantees as collateralsecurity from certain counter partiesbelow investment grade
counterparties in caseour normal course of adverse market
conditions.business.
We trade electricity and gas contracts with numerous counter parties.counterparties.
Since our open energy trading contracts are valued based on changes in market
prices of the related commodities, our exposures can change.change daily. We believe that
our credit and market exposures with any one counter partycounterparty is not material.
QUANTITATIVE MARKET RISK
We employ policiesmaterial to
financial condition at March 31, 2002. At March 31, 2002 approximately 7% of the
counterparties were below investment grade as expressed in terms of Net Mark to
Market Assets. Net Mark to Market Assets represents the aggregate difference
(either positive or negative) between the forward market price for the remaining
term of the contract and procedures to identify, assess and manage market
risk exposure. One procedure is the risk measurement model Value at Risk (VaR).
VaR is used daily to measure and monitor trading risk. VaR operates on the
variance - covariance method using historical prices to estimate volatility and
correlation and assumes a 95% confidence level and a one-day holding period.
contractual price. The following table representsapproximates
counterparty credit quality and exposure for AEP.
Futures,
Forwards and
Counterparty Swap Contracts Options Total
Credit Quality:
March 31, 2002
(in millions)
AAA/Exchanges $ 1 $ - $ 1
AA 104 39 143
A 304 14 318
BBB 1,021 260 1,281
Below Investment
Grade 94 43 137
------- ---- ---
Total $1,524 $356 $1,880
====== ==== ======
The counterparty credit quality and exposure for the high, averageregistrant
subsidiaries is generally consistent with that of AEP.
We enter into transactions for electricity and low VaRs for AEP's
electricnatural gas as
part of wholesale trading operations. Electric and gas trading activitiestransactions are
executed over the counter with counterparties or through brokers. Gas
transactions are also executed through brokerage accounts with brokers who
are registered with the Commodity Futures Trading Commission. Brokers and
electric trading for its registrant
subsidiaries. VaR for AEPcounterparties require cash or cash related instruments to be deposited on
these transactions as margin against open positions. The combined margin
deposits at March 31, 2002 and Registrant Subsidiaries:
Nine Months Ended Year Ending
September 30, December 31, 2001 2000were $230 million and
$55 million. These margin accounts are restricted and therefore are not included
in cash and cash equivalents on the Balance Sheet. We can be subject to further
margin requirements should related commodity prices change.
We recognize the net change in the fair value of all open trading
contracts, a practice commonly called mark-to-market accounting, in accordance
with generally accepted accounting principles and include the net change in
mark-to-market amounts on a net discounted basis in revenues. The marking to
market of open trading contracts in the first quarter of 2002 resulted in an
unrealized increase in revenues of $43 million. The fair value of open
short-term trading contracts are based on exchange prices and broker quotes. The
fair value of open long-term trading contracts are based mainly on Company
developed valuation models. This fair value is present valued and reduced by
appropriate reserves for counterparty credit risks and liquidity risk. The
models are derived from internally assessed market prices with the exception of
the NYMEX gas curve, where we use daily settled prices. Forward price curves are
developed for inclusion in the model based on broker quotes and other available
market data. The curves are within the range between the bid and ask prices. The
end of the month liquidity reserve is based on the difference in price between
the price curve and the bid price of the bid ask prices if we have a long
position and the ask price if we have a short position. This provides for a
conservative valuation net of the reserves.
The use of these models to fair value open long-term trading
contracts has inherent risks relating to the underlying assumptions employed by
such models. Independent controls are in place to evaluate the reasonableness of
the price curve models. Significant adverse or favorable effects on future
results of operations and cash flows could occur if market prices, at the time
of settlement, do not correlate with the Company developed price models.
The effect on the Consolidated Statements of Income of marking to
market open electricity trading contracts in the Company's regulated
jurisdictions is deferred as regulatory assets or liabilities since these
transactions are included in cost of service on a settlement basis for
ratemaking purposes. Unrealized mark-to-market gains and losses from trading are
reported as assets and liabilities, respectively.
The following table shows net revenues (revenues less fuel and
purchased energy expense) and their relationship to the mark-to-market revenues
(the change in fair value of open trading positions).
March 31,
---------
2002
----
(in millions)
Revenues (including mark-to-market
adjustment) $13,414
Fuel and Purchased Energy Expense 11,307
-------
Net Revenues $ 2,107
=======
Mark-to-Market Revenues on Open Trading Positions $47*
===
Percentage of Net Revenues Represented by
Mark-to-Market on Open Trading Positions 2%
==
*Excludes reversal of $266 million of mark to market for contracts that
settled in the 1st quarter of 2002.
The following tables analyze the changes in fair values of trading
assets and liabilities. The first table "Net Fair Value of Energy Trading
Contracts and Related Derivatives" shows how the net fair value of energy
trading contracts was derived from the amounts included in the balance sheet
line item "energy trading and derivative contracts." The next table "Energy
Trading Contracts and Related Derivatives" disaggregates realized and unrealized
changes in fair value; identifies changes in fair value as a result of changes
in valuation methodologies; and reconciles the net fair value of energy trading
contracts and related derivatives at December 31, 2001 of $448 million to March
31, 2002 of $355 million. Contracts realized/settled during the period include
both sales and purchase contracts. The third table "Energy Trading Contract
Maturities" shows exposures to changes in fair values and realization periods
over time for each method used to determine fair value.
Net Fair Value of Energy Trading Contracts and Related Derivatives
March 31, December 31,
------------- ------------
2002 2001
---- High Average Low High Average Low----
(in millions) (in millions)
AEP $28 $14 $5 $32 $10 $1
APCo 2 1 1 6 2Energy Trading and Derivative Contracts:
Current Asset $ 9,327 $ 8,572
Long-term Asset 3,268 2,370
Current Liability (9,231) (8,311)
Long-term Liability (3,066) (2,183)
------ ------
Net Fair Value of Energy Trading Contracts and
Derivative Contracts 298 448
Less non-trading related derivatives (57) -
CPL 1 1 - 4 1 -
CSPCo 1 1 - 3 1 -
I&M 1 1 - 4 1 -
KPCo - - - 1 - -
OPCo 2 1 - 5 2 -
PSO 1 1 - 3 1 -
SWEPCo 1 1 - 4 1 -
WTU - - - 1 - -
Near term--- ---
Net Fair Value of Energy Trading Contracts and
Related Derivatives $ 355 $ 448
===== =====
The above net fair value of energy trading contracts and related derivatives
includes $47 million, at March 31, 2002, in unrealized mark-to-market gains that
are recognized in the income statement for the quarter ended March 31, 2002.
Also included in the above net fair value of energy trading contracts and
related derivatives are option premiums that are deferred until the related
contracts settle and the portion of changes in commodityfair values of electricity
trading contracts that are deferred for ratemaking purposes.
AEP Consolidated Energy Trading Contracts and Related Derivatives
(in millions)
Total
Net Fair Value of Energy Trading Contracts and Related Derivatives
at December 31, 2001 $ 448
(Gain) Loss from Contracts realized/settled during period (271) (a)
Adjustments to (gain) Loss for Contracts entered into and
settled during period (16) (a)
Fair Value of new open contracts when entered into during the period 34 (b)
Net option premium payments 119
Changes in market value of contracts 41 (c)
-----
Net Fair Value of Energy Trading Contracts and Commodity Derivatives
at March 31, 2002 $ 355 (d)
=====
(a) "(Gain) Loss from Contracts Realized or Otherwise Settled During the
Period" include realized gains from energy trading contracts and
related derivatives that settled during 2002 that were entered into
prior to 2002, as well as during 2002. "Adjustments to gains or losses
for Contracts Entered into and Settled During the Period" discloses
the realized gains from settled energy trading contracts that were
both entered into and closed within 2002 that are included in the
total gains of $271 million, but not included in the ending balance of
open contracts.
(b) The "Fair Value of New Open Contracts When Entered Into During Period"
represents the fair value of long-term contracts entered into with
customers during 2002. 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 representative of the delivery location.
(c) "Change in market Value of Contracts" represents the fair value change
in the trading portfolio due to market fluctuations during the current
period. Market fluctuations are attributable to various factors such
as supply/demand, weather, storage, etc.
(d) The net change in the fair value of energy trading contracts for 2002
that resulted in a decrease of $93 million ($355 million less $448
million) represents the balance sheet change. The net mark-to-market
gain on energy trading contracts of $47 million represents the impact on
earnings related to open trading contracts as of March 31, 2002. The
difference is related primarily to settlement of prior period open
energy trading contracts ($266 million decrease); regulatory deferrals
of certain mark-to-market gains that were recorded as regulatory
liabilities and not expected to materially
affect our resultsreflected in the income statement for those
companies that operate in regulated jurisdictions; and deferrals of
operations, cash flowsoption premiums included in the above analysis, which do not have a
mark-to-market income statement impact.
Energy Trading Contracts
(in thousands)
APCo CPL CSPCo
Net Fair Value of Energy Trading
Contracts at December 31, 2001 $ 75,701 $ 3,857 $ 48,449
(Gain) Loss from Contracts
realized/settled during period (7,935) (388) (5,212)
Adjustments to (gain) loss for
Contracts entered into and settled
during the period 1,742 99 1,139
Fair Value of new open Contracts
when entered into during period 8,804 1,045 5,752
Net option premium payments 1,313 - 859
Changes in market value of Contracts 3,123 (7,221) 4,835
-------- ------- --------
Net Fair Value of Energy Trading
Contracts at March 31, 2002 $ 82,748 $(2,608) $ 55,822
======== ======= ========
Energy Trading Contracts
(in thousands)
I&M KPCo OPCo
Net Fair Value of Energy Trading
Contracts at December 31, 2001 $ 61,345 $12,729 $ 65,446
(Gain) Loss from Contracts
realized/settled during period (5,639) (2,056) (7,088)
Adjustments to (gain) loss for
Contracts entered into and settled
During the period 1,232 450 1,549
Fair Value of new open Contracts
when entered into during period 6,224 2,272 7,823
Net option premium payments 929 339 1,168
Changes in market value of Contracts 1,135 1,263 14,642
------- ------- --------
Net Fair Value of Energy Trading
Contracts at March 31, 2002 $ 65,226 $14,997 $ 83,540
======== ======= ========
Energy Trading Contracts
(in thousands)
PSO SWEPCo WTU
Net Fair Value of Energy Trading
Contracts at December 31, 2001 $ 2,434 $ 2,900 $ 915
(Gain) Loss from Contracts
realized/settled during the period (294) (339) (115)
Adjustments to (gain) loss for
Contracts Entered into and settled
during period 75 87 29
Fair Value of new open Contracts
when entered into during period 796 914 310
Net option premium payments - - -
Changes in market value of Contracts (7,177) (8,238) 30
------- ------- -------
Net Fair Value of Energy Trading
Contracts at March 31, 2002 $(4,166) $(4,676) $ 1,169
======= ======= =======
Energy Trading Contract Maturities
Fair Value of Contracts at March 31, 2002
------------------------------------------------------------------
Maturities
------------------------------------------------------
(in millions)
AEP Consolidated Less than In Excess Total Fair
Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value
- -------------------- ------ --------- --------- ---------- ---------
Prices actively quoted (a) $(177) $ 52 $ - $ - $(125)
Prices provided by other external
Sources (b) 280 22 - - 302
Prices based on models and other
Valuation methods (c) 10 89 52 27 178
----- ---- --- --- -----
Total $ 113 $163 $52 $27 $ 355
===== ==== === === =====
Energy Trading Contract Maturities
Fair Value of Contracts at March 31, 2002
------------------------------------------------------------------
Maturities
------------------------------------------------------
(in thousands)
Less than In Excess Total Fair
Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value
- -------------------- ------ --------- --------- ---------- ---------
APCo
Prices provided by other
External Sources (b) $20,369 $15,379 $ - $ - $35,748
Prices based on models and other
Valuation methods (c) 5,054 22,529 11,637 7,780 47,000
------- ------- ------- ------ -------
Total $25,423 $37,908 $11,637 $7,780 $82,748
======= ======= ======= ====== =======
CPL
Prices provided by other
External Sources (b) $(4,081) $ 667 $ - $ - $(3,414)
Prices based on models and other
Valuation methods (c) (1,013) 977 505 337 806
-------- ------ ------ ----- -------
Total $(5,094) $1,644 $ 505 $ 337 $(2,608)
======== ====== ====== ===== =======
CSP
Prices provided by other
External Sources (b) $14,746 $10,038 $ - $ - $24,784
Prices based on models and other
Valuation methods (c) 3,659 14,705 7,596 5,078 31,038
------- ------- ------ ------ -------
Total $18,405 $24,743 $7,596 $5,078 $55,822
======= ======= ====== ====== =======
KPCo
Prices provided by other
External Sources (b) $ 176 $3,964 $ - $ - $ 4,140
Prices based on models and other
Valuation methods (c) 44 5,808 3,000 2,005 10,857
------ ------ ------ ------ -------
Total $ 220 $9,772 $3,000 $2,005 $14,997
====== ====== ====== ====== =======
I&M
Prices provided by other
External Sources (b) $21,918 $10,160 $ - $ - $32,078
Prices based on models and other
Valuation methods (c) 5,438 14,883 7,688 5,139 33,148
------- ------- ------ ------ -------
Total $27,356 $25,043 $7,688 $5,139 $65,226
======= ======= ====== ====== =======
OPCo
Prices provided by other
External Sources (b) $23,307 $14,608 $ - $ - $37,915
Prices based on models and other
Valuation methods (c) 5,783 21,399 11,053 7,390 45,625
------- ------- ------- ------ -------
Total $29,090 $36,007 $11,053 $7,390 $83,540
======= ======= ======= ====== =======
PSO
Prices provided by other
External Sources (b) $(4,725) $ 464 $ - $ - $(4,261)
Prices based on models and other
Valuation methods (c) (1,172) 680 351 236 95
-------- ------ ------ ---- -------
Total $(5,897) $1,144 $ 351 $236 $(4,166)
======== ====== ====== ==== =======
SWEPCo
Prices provided by other
External Sources (b) $(5,338) $ 533 $ - $ - $(4,805)
Prices based on models and other
Valuation methods (c) (1,325) 781 403 270 129
-------- ------ ------ ---- -------
Total $(6,663) $1,314 $ 403 $270 $(4,676)
======== ====== ====== ==== =======
WTU
Prices provided by other
External Sources (b) $ (667) $ 537 $ - $ - $ (130)
Prices based on models and other
Valuation methods (c) (165) 786 406 272 1,299
-------- ------ ------ ---- ------
Total $ (832) $1,323 $ 406 $272 $1,169
======== ====== ====== ==== ======
(a) "Prices Actively Quoted" represents the Company's exchange traded
natural gas futures.
(b) "Prices Provided by Other External Sources" represents the Company's
positions in natural gas, power, and financial conditions.coal at points where
over-the-counter broker quotes are available. Some prices from
external sources are quoted as strips (one bid/ask for Nov-Mar,
Apr-Oct, etc). Such transactions have also been included in this
category.
(c) "Prices Based on Models and Other Valuation Methods" contain the
following: the value of the Company's adjustments for liquidity and
counterparty credit exposure, the value of contracts not quoted by an
exchange or an over-the-counter broker, the value of transactions for
which an internally developed price curve was developed as a result of
the long dated nature of certain transactions, and the value of
certain structured transactions.
PART II. OTHER INFORMATION
Item 5. Other Information.
AEP and APCo
Reference is made to pages 17 and 18 of the Annual Report on Form 10-K
for the year ended December 31, 2001 (2001 10-K) for a discussion of APCo's
proposed transmission facilities. On April 23, 2002,the Forest Service issued
its Supplemental Draft Environmental Impact Statement (SDEIS). In the SDEIS, the
Forest Service identified the Wyoming-Jacksons Ferry Project as the preferred
alternative.
AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
Reference is made to page 26 of the 2001 10-K for a discussion of the
ozone and particulate matter National Ambient Air Quality Standards. On March
26, 2002, the U. S. Court of Appeals issued a unanimous decision holding that
Federal EPA's promulgation of revised national ambient air quality standards for
fine particulate matter and ozone was not arbitrary and capricious.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
Exhibit 12 - Computation of Consolidated Ratio of Earnings to
Fixed Charges.
(b) Reports on Form 8-K:
AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo OPCo, PSO, SWEPCo and WTU
No reports on Form 8-K were filed during the quarter ended
September 30,
2001.March 31, 2002.
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The 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/Armando A. Pena By: /s/Joseph M. Buonaiuto
----------------------- ----------------------------
Armando A. Pena Joseph M. Buonaiuto
Treasurer Controller and Chief Accounting Officer
AEP GENERATING COMPANY
APPALACHIAN POWER COMPANY
CENTRAL POWER AND LIGHT COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
WEST TEXAS UTILITIES COMPANY
By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto
----------------------- ---------------------------------------------------------------------
Armando A. Pena Joseph M. Buonaiuto
TreasurerVice President and Controller and Chief Accounting Officer
Treasurer
Date: November 12, 2001May 13, 2002