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
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from to
Commission Registrant, State of Incorporation I.R. S. Employer
File Number Address, and Telephone Number Identification No.
- ----------- ----------------------------- ------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA 73-0410895
(An Oklahoma Corporation)
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455
(A Delaware Corporation)
0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation)
75-0646790 1 Riverside Plaza, Columbus, Ohio
43215-2373 Telephone (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 April 30, 2002 was 322,822,489.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended March 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-6
Consolidated Financial Statements A-7 - A-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-4
Consolidated Financial Statements C-5 - C-9
Central Power and Light Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations D-1 - D-4
Consolidated Financial Statements D-5 - D-8
Columbus Southern Power Company and Subsidiaries:
Management's Narrative Analysis of Results of Operations E-1 - E-5
Consolidated Financial Statements E-6 - E-9
Indiana Michigan Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations F-1 - F-5
Consolidated Financial Statements F-6 - F-10
Kentucky Power Company
Management's Narrative Analysis of Results of Operations G-1 - G-4
Financial Statements G-5 - G-9
Ohio Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations H-1 - H-4
Consolidated Financial Statements H-5 - H-9
Public Service Company of Oklahoma and Subsidiaries:
Management's Narrative Analysis of Results of Operations I-1 - I-4
Consolidated Financial Statements I-5 - I-8
Southwestern Electric Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations J-1 - J-4
Consolidated Financial Statements J-5 - J-8
West Texas Utilities Company:
Management's Narrative Analysis of Results of Operations K-1 - K-4
Financial Statements K-5 - K-8
Footnotes to Financial Statements L-1 - L-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-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.
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.
DOE................................ United States Department of Energy.
EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT.............................. The Electric Reliability Council of Texas.
FASB............................... Financial Accounting Standards Board.
Federal EPA........................ United States Environmental Protection Agency.
FERC............................... Federal Energy Regulatory Commission.
GAAP............................... Generally Accepted Accounting Principles.
I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS................................ Internal Revenue Service.
IURC............................... Indiana Utility Regulatory Commission.
ISO................................ Independent system operator.
KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary.
KPSC............................... Kentucky Public Service Commission.
KWH................................ Kilowatthour.
LIG................................ Louisiana Intrastate Gas.
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.
NEIL............................... Nuclear Electric Insurance Limited.
NOx................................ Nitrogen oxide.
NOx 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; 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 Central Power and Light
Company, an AEP electric utility subsidiary .
SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary.
Texas Restructuring 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 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
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
American 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 of $181 million or $0.56 per share was
down 32% from last year's earnings of $266 million or $0.83 per share.
Unfavorable market conditions and the effect 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 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.
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 earned, but unbilled and/or not yet metered gas.
Energy Marketing and Trading Activities - We engage in non-regulated wholesale
electricity and natural 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 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 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 the 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 adverse 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 reports upon settlement sales under
forward trading contracts as revenues and purchases under forward trading
contracts as purchased energy expense. If settled forward sale and purchase
contracts were reported on a net basis, the amounts of revenues and purchased
energy expense reported would have been:
Three Months Ended March 31,
2002 2001
(in millions)
Gross Net Gross Net
----- --- ----- ---
Revenues:
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 Energy Expense:
Electricity Marketing and Trading $ 7,289 $ 764 $ 8,221 $1,052
Gas Marketing and Trading 3,673 464 3,538 194
Other Investments 345 345 343 343
------- ------ ------- ------
Total $11,307 $1,573 $12,102 $1,589
======= ====== ======= ======
We defer as regulatory assets or liabilities the effect on net income
of marking to market open forward electricity trading contracts in our 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 the 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 marketing and trading. In March 2001 we completed the
sale of Frontera, one of the generating plants required to be divested under the
FERC approved merger settlement agreements. The sale resulted in a $46 million
after 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 revenues is mainly due to a decrease in electric
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 power generation and purchases 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 and 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
outstanding balance of long-term debt since the first quarter of 2001, the
refinancing of debt at favorable interest rates and a reduction in 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 March 31,
2002 2001
---- ----
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 13,414 14,235
------- -------
EXPENSES:
Fuel and Purchased Energy:
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 1,042 958
Depreciation and Amortization 359 336
Taxes Other Than Income Taxes 186 168
------- -------
TOTAL OPERATING EXPENSES 12,894 13,564
------- -------
OPERATING INCOME 520 671
OTHER INCOME 17 53
OTHER EXPENSES 22 19
LESS: INTEREST 228 266
PREFERRED STOCK DIVIDEND REQUIREMENTS OF
SUBSIDIARIES 2 3
MINORITY INTEREST IN FINANCE SUBSIDIARY 9 -
------- -------
239 269
INCOME BEFORE INCOME TAXES 276 436
INCOME TAXES 95 170
------- -------
NET INCOME $ 181 $ 266
======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 322 322
=== ===
EARNINGS PER SHARE (Basic and Dilutive): $0.56 $0.83
===== =====
CASH DIVIDENDS PAID PER SHARE $0.60 $0.60
===== =====
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(in millions)
ASSETS
- ------
CURRENT ASSETS:
Cash and Cash Equivalents $ 306 $ 333
Accounts Receivable (net) 2,554 1,882
Fuel, Materials and Supplies 963 1,066
Energy Trading and Derivative Contracts 9,327 8,572
Other 1,130 710
------- -------
TOTAL CURRENT ASSETS 14,280 12,563
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 17,483 17,477
Transmission 5,937 5,879
Distribution 11,431 11,310
Other (including gas, coal mining and
nuclear fuel) 4,838 4,941
Construction Work in Progress 1,179 1,102
------- -------
Total Property, Plant and Equipment 40,868 40,709
Accumulated Depreciation and Amortization 16,421 16,166
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 24,447 24,543
------- -------
REGULATORY ASSETS 2,573 3,162
------- -------
SECURITIZED TRANSITION ASSET 758 -
------- -------
INVESTMENTS IN POWER, DISTRIBUTION AND
COMMUNICATIONS PROJECTS 599 677
------- -------
GOODWILL 1,591 1,546
------- -------
INTANGIBLE ASSETS 471 441
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 3,268 2,370
------- -------
OTHER ASSETS 2,166 1,979
------- -------
TOTAL $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)
March 31, 2002 December 31, 2001
-------------- -----------------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 2,162 $ 2,245
Short-term Debt 3,984 4,025
Long-term Debt Due Within One Year 1,231 1,430
Energy Trading And Derivative Contracts 9,231 8,311
Other 2,519 2,088
------- -------
TOTAL CURRENT LIABILITIES 19,127 18,099
------- -------
LONG-TERM DEBT 10,571 9,753
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 3,066 2,183
------- -------
DEFERRED INCOME TAXES 4,765 4,823
------- -------
DEFERRED INVESTMENT TAX CREDITS 482 491
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 1,175 948
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 192 194
------- -------
OTHER NONCURRENT LIABILITIES 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 321 321
------- -------
MINORITY INTEREST IN FINANCE SUBSIDIARY 750 750
------- -------
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 156 156
------- -------
COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
2002 2001
---- ----
Shares Authorized.. . 600,000,000 600,000,000
Shares Issued. . . . .331,618,850 331,234,997
(8,999,992 shares were held in treasury at
March 31, 2002 and December 31, 2001) 2,156 2,153
Paid-in Capital 2,912 2,906
Accumulated Other Comprehensive Income (Loss) (170) (126)
Retained Earnings 3,288 3,296
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 8,186 8,229
------- -------
TOTAL $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)
Three Months Ended March 31,
2002 2001
---- ----
(in millions)
OPERATING ACTIVITIES:
Net Income $ 181 $ 266
Adjustments for Noncash Items:
Depreciation and Amortization 362 352
Deferred Federal Income Taxes (63) 68
Deferred Investment Tax Credits (9) (9)
Net Mark to Market Adjustment of Energy Trading Contracts 219 (57)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (832) 615
Fuel, Materials and Supplies 100 (13)
Accrued Utility Revenues (55) 39
Prepayments and Other (58) (68)
Accounts Payable 20 (499)
Taxes Accrued 8 15
Interest Accrued 106 65
Rent Accrued - Rockport Plant Unit 2 37 37
Option Premiums 52 156
Change in Other Assets (339) (378)
Change in Other Liabilities 257 (5)
----- -----
Net Cash Flows From Operating Activities (14) 584
----- -----
INVESTING ACTIVITIES:
Construction Expenditures (353) (315)
Other (25) 109
----- -----
Net Cash Flows Used For Investing Activities (378) (206)
----- -----
FINANCING ACTIVITIES:
Issuance of Common Stock 14 3
Issuance of Long-term Debt 914 132
Change in Short-term Debt (net) (41) (266)
Retirement of Long-term Debt (313) (209)
Dividends Paid on Common Stock (193) (193)
----- -----
Net Cash Flows Used For Financing Activities 381 (533)
----- -----
Effect of Exchange Rate Change on Cash (16) (7)
----- -----
Net Decrease in Cash and Cash Equivalents (27) (162)
Cash and Cash Equivalents at Beginning of Period 333 437
----- -----
Cash and Cash Equivalents at End of Period $ 306 $ 275
===== =====
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, 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 Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- -------------- -----
(in millions)
JANUARY 1, 2001 $2,152 $2,915 $3,090 $(103) $8,054
Issuance of Common Stock 4 4
Common Stock Dividends (193) (193)
Other (5) (5)
------
7,860
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes
Currency Translation Adjustment (82) (82)
Unrealized Gain on Securities 13 13
Net Income 266 266
------
Total Comprehensive Income 197
------ ------ ------ ----- ------
MARCH 31, 2001 $2,152 $2,914 $3,163 $(172) $8,057
====== ====== ====== ===== ======
JANUARY 1, 2002 $2,153 $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
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
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 net of temporary cash investments.
Net income declined $87,000 for the first quarter.
A decrease in operating revenues of $10,632,000 resulted from a decrease
in recoverable expenses, primarily fuel, as 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 declined 18% as follows:
Increase (Decrease)
-------------------
(in thousands) %
-------------- -
Fuel $(10,145) (37)
Rent - Rockport Plant
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 decreased due to the decline in generation.
The increase in other operation expense is primarily due to higher
costs for employee benefits and property insurance.
Maintenance expense increased due to planned 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 the year 2001 than actually occurred. The over-accrual was
adjusted later in 2001.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING REVENUES - Sales to AEP Affiliates $49,875 $60,507
------- -------
OPERATING EXPENSES:
Fuel 17,500 27,645
Rent - Rockport Plant Unit 2 17,071 17,071
Other Operation 3,222 2,958
Maintenance 2,976 1,926
Depreciation 5,633 5,586
Taxes Other Than Income Taxes 1,053 1,043
Income Taxes 653 2,471
------- -------
TOTAL OPERATING EXPENSES 48,108 58,700
------- -------
OPERATING INCOME 1,767 1,807
NONOPERATING INCOME 2 -
NONOPERATING EXPENSES 12 9
NONOPERATING INCOME TAX CREDITS 832 871
INTEREST CHARGES 696 689
------- -------
NET INCOME $ 1,893 $ 1,980
======= =======
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $13,761 $ 9,722
NET INCOME 1,893 1,980
CASH DIVIDENDS DECLARED 1,050 959
------- -------
BALANCE AT END OF PERIOD $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)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $639,544 $638,297
General 3,012 3,012
Construction Work in Progress 9,649 6,945
-------- --------
Total Electric Utility Plant 652,205 648,254
Accumulated Depreciation 342,515 337,151
-------- --------
NET ELECTRIC UTILITY PLANT 309,690 311,103
-------- --------
OTHER PROPERTY AND INVESTMENTS 119 119
-------- --------
CURRENT ASSETS:
Cash and Cash Equivalents 4,212 983
Accounts Receivable:
Affiliated Companies 21,007 22,344
Miscellaneous 147 147
Fuel - at average cost 16,555 15,243
Materials and Supplies - at average cost 4,382 4,480
Prepayments 128 244
-------- --------
TOTAL CURRENT ASSETS 46,431 43,441
-------- --------
REGULATORY ASSETS 5,149 5,207
-------- --------
DEFERRED CHARGES 3,816 1,471
-------- --------
TOTAL ASSETS $365,205 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 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 14,604 13,761
-------- --------
Total Common Shareholder's Equity 39,038 38,195
Long-term Debt 44,795 44,793
-------- --------
TOTAL CAPITALIZATION 83,833 82,988
-------- --------
OTHER NONCURRENT LIABILITIES 74 76
-------- --------
CURRENT LIABILITIES:
Advances from Affiliates 16,538 32,049
Accounts Payable:
General 4,241 7,582
Affiliated Companies 3,774 1,654
Taxes Accrued 10,306 4,777
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Other 2,938 3,481
-------- --------
TOTAL CURRENT LIABILITIES 61,224 54,506
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
PLANT UNIT 2 115,225 116,617
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credit 55,469 56,304
Amounts Due to Customers for Income Taxes 22,059 22,725
-------- --------
TOTAL REGULATORY LIABILITIES 77,528 79,029
-------- --------
DEFERRED INCOME TAXES 27,171 27,975
-------- --------
DEFERRED CREDITS 150 150
-------- --------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $365,205 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 1,893 $ 1,980
Adjustment for Noncash Items:
Depreciation 5,633 5,586
Deferred Federal Income Taxes (1,470) (1,462)
Deferred Investment Tax Credits (835) (837)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (1,392) (1,392)
Deferred Property Taxes (2,693) (2,737)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable 1,337 500
Fuel, Materials and Supplies (1,214) 661
Accounts Payable (1,221) 3,783
Taxes Accrued 5,529 6,131
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets 586 199
Change in Other Liabilities (545) 375
-------- --------
Net Cash Flow From Operating Activities 24,072 31,251
-------- --------
INVESTING ACTIVITIES - Construction Expenditures (4,282) (432)
-------- --------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) (15,511) (27,849)
Dividends Paid (1,050) (959)
-------- --------
Net Cash Flows Used For Financing Activities (16,561) (28,808)
-------- --------
Net Increase in Cash and Cash Equivalents 3,229 2,011
Cash and Cash Equivalents at Beginning of Period 983 2,757
-------- --------
Cash and Cash Equivalents at End of Period $ 4,212 $ 4,768
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,108,000 and $644,000
and for income taxes was $176,000 and $1,349,000 in 2002 and 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
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
APCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of 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 its behalf by
the AEP Power Pool.
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 electricity demand driven largely by mild weather and the slow
recovery from the economic recession. Sales to AEP affiliates declined as a
result of the mild weather and economic conditions that reduced electricity
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
Trading 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 due to an increase in electric 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 marketing and trading purchases was mainly
due to reduced prices caused by decreased electricity demand driven largely by
mild weather and the economic recession.
The decrease in maintenance expense is due to the effect of boiler plant
maintenance performed on certain plants in the first quarter of 2001.
Depreciation and amortization expense increased due to the additional
accelerated amortization beginning in July 2001 of transition regulatory assets
in connection with the discontinuance of SFAS 71 in the Company's West Virginia
jurisdiction whereby net generation-related regulatory assets were transferred
to the distribution portion of the business commensurate with their recovery
through regulated rates (see Note 5 for further discussion of the effects of
restructuring). Additional investments in distribution and production plant also
contributed to the increase in depreciation and amortization expense.
The decrease in income taxes from operations was due to a decrease in
pre-tax operating income.
Nonoperating income and expense decreased largely due to reduced margins
on electricity trading outside of AEP's traditional marketing area caused by
decreased electricity demand resulting from mild weather and the slow recovery
from the economic recession.
Interest charges decreased due primarily to increased allowances for
borrowed funds as a result of increased construction expenditures and the
retirement of first mortgage bonds on March 1, 2001 and the retirement of senior
unsecured notes in June 2001.
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 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 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)
March 31, 2002 December 31, 2001
------------- -----------------
(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 715,928 715,786
Accumulated Other Comprehensive Income (Loss) (197) (340)
Retained Earnings 174,651 150,797
---------- ----------
Total Common Shareowner's Equity 1,150,840 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 1,476,819 1,476,552
---------- ----------
TOTAL CAPITALIZATION 2,656,309 2,631,903
---------- ----------
OTHER NONCURRENT LIABILITIES 84,672 84,104
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 80,007 80,007
Advances from Affiliates 259,826 291,817
Accounts Payable - General 100,440 131,387
Accounts Payable - Affiliated Companies 126,921 84,518
Taxes Accrued 84,712 55,583
Customer Deposits 14,874 13,177
Interest Accrued 39,286 21,770
Energy Trading Contracts 740,311 549,703
Other 71,916 75,299
---------- ----------
TOTAL CURRENT LIABILITIES 1,518,293 1,303,261
---------- ----------
DEFERRED INCOME TAXES 700,120 703,575
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 37,230 38,328
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 463,896 257,129
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 91,562 89,638
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $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)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 55,341 $ 61,787
Adjustments for Noncash Items:
Depreciation and Amortization 46,800 43,745
Deferred Federal Income Taxes (3,644) 19,438
Deferred Investment Tax Credits (1,098) (1,106)
Deferred Power Supply Costs (net) 352 121
Mark to Market of Energy Trading Contracts (6,653) (59,398)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (51,419) 82,071
Fuel, Materials and Supplies 12,659 3,091
Accrued Utility Revenues 7,013 51,292
Accounts Payable 11,456 6,086
Taxes Accrued 29,129 5,417
Interest Accrued 17,516 17,618
Change in Other Assets (7,043) (16,226)
Change in Other Liabilities 1,366 (2,789)
--------- ---------
Net Cash Flows From Operating Activities 111,775 211,147
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (62,685) (39,922)
Proceeds from Sale of Property 583 1,182
--------- ---------
Net Cash Flows Used For Investing Activities (62,102) (38,740)
--------- ---------
FINANCING ACTIVITIES:
Change in Short-term Debt (net) - (191,495)
Change in Advances From Affiliates (31,991) 153,572
Retirement of Long-term Debt - (100,000)
Dividends Paid on Common Stock (30,984) (32,399)
Dividends Paid on Cumulative Preferred Stock (361) (361)
--------- ---------
Net Cash Flows Used For Financing Activities (63,336) (170,683)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (13,663) 1,724
Cash and Cash Equivalents at Beginning of Period 13,663 5,847
--------- ---------
Cash and Cash Equivalents at End of Period $ - $ 7,571
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $9,222,000 and $13,156,000
and for income taxes was $9,593,000 and $13,543,000 in 2002 and 2001,
respectively. Noncash acquisitions under capital leases were $-0- and $1,512,000
in 2002 and 2001, respectively.
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
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 to other utilities, municipalities, rural electric cooperatives and
beginning in 2002 to retail electric providers (REPs) in Texas, (see
"Introduction of 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 forward trades with
other utility systems and power 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
utility. During the year 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
is 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 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 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.
Results of Operations
Net income decreased $10.6 million, or 30%, primarily due to mild
winter weather and a slow recovery from the economic recession. Operating
revenues decreased $200 million for the quarter as shown below:
Increase (Decrease)
(in millions) %
Electricity Marketing
and Trading* $(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 bundled retail rates to energy delivery.
N.M. = Not Meaningful
Electricity marketing and trading revenues decreased $361 million as a
result of several factors, including the elimination of retail sales in the
ERCOT area as of January 1, 2002, a decrease in energy trading, and mild winter
weather.
The significant increase in Sales to AEP Affiliates is due to the
introduction on January 1, 2002 of customer 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
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 due to a decrease in the average unit cost of
fuel resulting from lower spot market natural gas prices.
Electricity marketing and trading purchases 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 pre-tax operating income.
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 Affiliates 179,661 20,788
-------- --------
Total Operating Revenues 403,223 603,412
-------- --------
OPERATING EXPENSES:
Fuel 54,328 151,853
Purchased Power:
Electric Marketing and 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 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 SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $3,171,938 $3,169,421
Transmission 693,317 663,655
Distribution 1,294,074 1,279,037
General 244,361 241,137
Construction Work in Progress 134,133 169,075
Nuclear Fuel 247,393 247,382
---------- ----------
Total Electric Utility Plant 5,785,216 5,769,707
Accumulated Depreciation and Amortization 2,476,402 2,446,027
---------- ----------
NET ELECTRIC UTILITY PLANT 3,308,814 3,323,680
---------- ----------
OTHER PROPERTY AND INVESTMENTS 48,989 47,950
---------- ----------
SECURITIZED TRANSITION ASSET 758,436 -
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 32,259 72,502
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 9,206 10,909
Accounts Receivable:
General 52,545 38,459
Affiliated Companies 61,588 6,249
Allowance for Uncollectable Accounts (211) (186)
Fuel Inventory - at LIFO cost 38,572 38,690
Materials and Supplies - at average cost 56,952 55,475
Energy Trading Contracts 56,534 212,979
Prepayments and Other Current Assets 6,967 2,742
---------- ----------
TOTAL CURRENT ASSETS 282,153 365,317
---------- ----------
REGULATORY ASSETS 227,140 226,806
---------- ----------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 179,384 959,294
---------- ----------
NUCLEAR DECOMMISSIONING TRUST FUND 100,763 98,600
---------- ----------
DEFERRED CHARGES 83,596 21,837
---------- ----------
TOTAL ASSETS $5,021,534 $5,115,986
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 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 $ 55,292 $ 168,888
Paid-in Capital 132,592 405,000
Retained Earnings 812,080 826,197
---------- ----------
Total Common Shareowner's Equity 999,964 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 136,250 136,250
Long-term Debt 1,736,183 988,768
---------- ----------
TOTAL CAPITALIZATION 2,878,364 2,531,070
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 164,200 265,000
Advances from Affiliates 238,830 354,277
Accounts Payable - General 37,545 65,307
Accounts Payable - Affiliated Companies 44,028 49,301
Customer Deposits 2,204 26,744
Over Recovered Fuel 58,956 57,762
Taxes Accrued 101,279 83,512
Interest Accrued 28,035 18,524
Energy Trading Contracts 61,628 219,486
Other 16,278 22,768
---------- ----------
TOTAL CURRENT LIABILITIES 752,983 1,162,681
---------- ----------
DEFERRED INCOME TAXES 1,157,840 1,163,795
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 121,591 122,892
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 29,774 62,138
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 80,982 73,410
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,021,534 $5,115,986
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 24,445 $ 35,031
Adjustments for Noncash Items:
Depreciation and Amortization 41,847 42,391
Deferred Income Taxes (8,083) 2,579
Deferred Investment Tax Credits (1,302) (1,302)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (69,400) 8,203
Fuel, Materials and Supplies (1,359) (15,468)
Fuel Recovery 1,194 2,073
Electricity Mark to Market 6,466 (9,260)
Accounts Payable (33,035) (18,115)
Taxes Accrued 17,767 27,571
Deferred Property Taxes - (29,292)
Change in Other Assets (53,865) (43,099)
Change in Other Liabilities (11,978) 22,934
--------- --------
Net Cash Flows From (Used For) Operating Activities (87,303) 24,246
--------- --------
INVESTING ACTIVITIES:
Construction Expenditures (21,002) (38,873)
Other - (354)
--------- --------
Net Cash Flows Used For Investing Activities (21,002) (39,227)
--------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 796,613 -
Retirement of Long-term Debt (149,998) (505)
Retirement of Common Stock (386,004) -
Change in Advances from Affiliates (net) (115,447) 43,156
Dividends Paid on Common Stock (38,502) (37,014)
Dividends Paid on Cumulative Preferred Stock (60) (60)
--------- --------
Net Cash Flows From Financing Activities 106,602 5,577
--------- --------
Net Decrease in Cash and Cash Equivalents (1,703) (9,404)
Cash and Cash Equivalents at Beginning of Period 10,909 14,253
--------- --------
Cash and Cash Equivalents at End of Period $ 9,206 $ 4,849
========= ========
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
2001, 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
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
Columbus Southern Power Company is a public utility engaged in the
generation, purchase, sale, transmission and distribution of 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 AEP's trading activities are allocated to CSPCo 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 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 electricity is in
AEP's traditional marketing area or 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 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. 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 electric
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 a
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 components
of operating expenses were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Fuel $ (1.4) (3)
Electricity Marketing and
Trading 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 was 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 market conditions that developed in the fourth
quarter of 2001.
Maintenance expenses decreased in the first quarter of 2002 due to
boiler overhaul work that was performed during the first quarter of 2001.
Expenses for maintaining distribution overhead lines and underground lines were
also lower in 2002.
A decrease in pre-tax operating income caused income taxes attributable
to operations to decline.
The increase in nonoperating income which was offset by a larger
increase in non-operating expenses was due to a reduction in net gains from 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 expense. The decrease reflects a reduction
in electricity prices and margins due to a decrease in demand reflecting milder
weather and the slow 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, the
refinancing of debt 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 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 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)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,575,390 $1,574,506
Transmission 402,391 401,405
Distribution 1,167,184 1,159,105
General 143,532 146,732
Construction Work in Progress 85,048 72,572
---------- ----------
Total Electric Utility Plant 3,373,545 3,354,320
Accumulated Depreciation and Amortization 1,399,457 1,377,032
---------- ----------
NET ELECTRIC UTILITY PLANT 1,974,088 1,977,288
---------- ----------
OTHER PROPERTY AND INVESTMENTS 39,793 40,369
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 339,985 193,915
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 6,497 12,358
Accounts Receivable:
Customers 46,077 41,770
Affiliated Companies 98,987 63,470
Miscellaneous 19,325 16,968
Allowance for Uncollectible Accounts (719) (745)
Fuel - at average cost 21,127 20,019
Materials and Supplies - at average cost 34,240 38,984
Accrued Utility Revenues 12,334 7,087
Energy Trading Contracts 500,539 347,198
Prepayments 32,951 28,733
---------- ----------
TOTAL CURRENT ASSETS 771,358 575,842
---------- ----------
REGULATORY ASSETS 258,725 262,267
---------- ----------
DEFERRED CHARGES 45,731 56,187
---------- ----------
TOTAL ASSETS $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)
March 31, 2002 December 31, 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 574,622 574,369
Retained Earnings 187,766 176,103
---------- ----------
Total Common Shareowner's Equity 803,414 791,498
Cumulative Preferred Stock - Subject to
Mandatory Redemption 10,000 10,000
Long-term Debt 571,441 571,348
---------- ----------
TOTAL CAPITALIZATION 1,384,855 1,372,846
---------- ----------
OTHER NONCURRENT LIABILITIES 34,687 36,715
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 220,500 220,500
Advances from Affiliates 210,490 181,384
Accounts Payable - General 53,925 62,393
Accounts Payable - Affiliated Companies 99,514 83,697
Taxes Accrued 96,417 116,364
Interest Accrued 14,514 10,907
Energy Trading Contracts 481,723 334,958
Other 33,421 34,600
---------- ----------
TOTAL CURRENT LIABILITIES 1,210,504 1,044,803
---------- ----------
DEFERRED INCOME TAXES 444,447 443,722
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 36,398 37,176
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 301,879 157,706
---------- ----------
DEFERRED CREDITS 16,910 12,900
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $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)
Three Months Ended March 31,
(in thousands)
2002 2001
---- ----
OPERATING ACTIVITIES:
Net Income $ 33,858 $ 37,671
Adjustments for Noncash Items:
Depreciation and Amortization 32,786 31,638
Deferred Federal Income Taxes (313) 6,957
Deferred Investment Tax Credits (778) (836)
Mark to Market of Energy Trading Contracts (5,849) (30,008)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (42,207) (10,067)
Fuel, Materials and Supplies 3,636 (4,345)
Accrued Utility Revenues (5,247) 9,638
Accounts Payable 7,349 17,605
Taxes Accrued (19,947) (38,504)
Interest Accrued 3,607 11,122
Other Assets 992 12,798
Other Liabilities 3,505 (6,442)
--------- --------
Net Cash Flows From Operating Activities 11,392 37,227
--------- --------
INVESTING ACTIVITIES:
Construction Expenditures (24,807) (33,007)
Proceeds from Sale of Property 389 -
--------- --------
Net Cash Flows Used For Investing Activities (24,418) (33,007)
--------- --------
FINANCING ACTIVITIES:
Change in Money Pool 29,106 13,477
Dividends Paid on Common Stock (21,766) (20,738)
Dividends Paid on Cumulative Preferred Stock (175) (262)
--------- --------
Net Cash Flows Used For Financing Activities 7,165 (7,523)
--------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (5,861) (3,303)
Cash and Cash Equivalents at Beginning of Period 12,358 11,600
--------- --------
Cash and Cash Equivalents at End of Period $ 6,497 $ 8,297
========= ========
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 2001,
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
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
I&M is a public utility engaged in the generation, purchase, sale,
transmission and distribution of 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 AEP's trading activities are allocated to I&M 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. 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 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
are 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 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 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 decline 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 certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The decrease in electricity marketing and trading revenues was due to a
decline in wholesale prices reflecting soft demand caused by the slow economic
recovery and mild winter weather. Revenues from sales to AEP affiliates declined
significantly reflecting less power being available for sale as one unit of the
Cook Nuclear Plant was shutdown for refueling and both units of 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 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 decreased primarily due to the decline 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 the Rockport 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
generating plants outages, property insurance and employee benefit costs.
The increase in maintenance expense is primarily due to costs related to
the outages.
Income tax expense attributable to operations decreased significantly
due primarily to a decline in pre-tax operating income.
The decrease in nonoperating income and nonoperating expenses is due to
lower prices for power sold and purchased outside of AEP's traditional marketing
area reflecting reduced demand.
The decrease in nonoperating income tax expense reflects a decline in
pre-tax nonoperating income.
Interest charges decreased due to a decline in short-term rates and
lower outstanding borrowings.
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 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 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)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,759,924 $2,758,160
Transmission 957,905 957,336
Distribution 899,146 900,921
General (including nuclear fuel) 220,140 233,005
Construction Work in Progress 91,819 74,299
---------- ----------
Total Electric Utility Plant 4,928,934 4,923,721
Accumulated Depreciation and Amortization 2,469,854 2,436,972
---------- ----------
NET ELECTRIC UTILITY PLANT 2,459,080 2,486,749
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS 844,616 834,109
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 385,768 215,544
---------- ----------
OTHER PROPERTY AND INVESTMENTS 124,762 127,977
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 10,849 16,804
Advances to Affiliates 37,422 46,309
Accounts Receivable:
Customers 66,101 60,864
Affiliated Companies 71,244 31,908
Miscellaneous 39,204 25,398
Allowance for Uncollectible Accounts (804) (741)
Fuel - at average cost 28,264 28,989
Materials and Supplies - at average cost 86,643 91,440
Energy Trading Contracts 579,967 399,195
Accrued Utility Revenues 5,405 2,072
Prepayments 9,838 6,497
---------- ----------
TOTAL CURRENT ASSETS 934,133 708,735
---------- ----------
REGULATORY ASSETS 414,045 408,927
---------- ----------
DEFERRED CHARGES 40,943 34,967
---------- ----------
TOTAL ASSETS $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)
March 31, 2002 December 31, 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 733,249 733,216
Accumulated Other Comprehensive Income (Loss) (2,576) (3,835)
Retained Earnings 84,508 74,605
---------- ----------
Total Common Shareowner's Equity 871,765 860,570
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,736 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,313,389 1,312,082
---------- ----------
TOTAL CAPITALIZATION 2,258,835 2,246,333
---------- ----------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 605,988 600,244
Other 86,872 87,025
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES 692,860 687,269
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 340,000 340,000
Accounts Payable:
General 77,745 90,817
Affiliated Companies 46,249 43,956
Taxes Accrued 91,152 69,761
Interest Accrued 28,265 20,691
Obligations Under Capital Leases 9,483 10,840
Energy Trading Contracts 554,916 383,714
Other 88,790 72,435
---------- ----------
TOTAL CURRENT LIABILITIES 1,236,600 1,032,214
---------- ----------
DEFERRED INCOME TAXES 389,177 400,531
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 103,604 105,449
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 76,665 77,592
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 347,151 175,581
---------- ----------
DEFERRED CREDITS 98,455 92,039
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $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)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 11,058 $ 32,363
Adjustments for Noncash Items:
Depreciation and Amortization 42,184 41,589
Amortization (Deferral) of Incremental
Nuclear Refueling Outage Expenses (net) (24,130) 316
Unrecovered Fuel and Purchased Power Costs 9,375 9,375
Amortization of Nuclear Outage Costs 10,000 10,000
Deferred Federal Income Taxes (7,132) (2,462)
Deferred Investment Tax Credits (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) (58,316) 43,803
Fuel, Materials and Supplies 5,522 (6,098)
Accrued Utility Revenues (3,333) -
Accounts Payable (10,779) (21,638)
Taxes Accrued 21,391 28,166
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets 8,328 (735)
Change in Other Liabilities 4,008 (17,909)
--------- ---------
Net Cash Flows From Operating Activities 12,678 106,188
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (26,398) (18,241)
Buyout of Nuclear Fuel Leases - (92,616)
--------- ---------
Net Cash Flows Used For Investing Activities (26,398) (110,857)
--------- ---------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 8,887 4,878
Dividends Paid on Cumulative Preferred Stock (1,122) (1,122)
--------- ---------
Net Cash Flows From Financing Activities 7,765 3,756
--------- ---------
Net Decrease in Cash and Cash Equivalents (5,955) (913)
Cash and Cash Equivalents at Beginning of Period 16,804 14,835
--------- ---------
Cash and Cash Equivalents at End of Period $ 10,849 $ 13,922
========= =========
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 2001,
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
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
KPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of 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 AEP's trading activities are allocated to KPCO 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. 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 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 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 45%.
The following analyzes the changes 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 distribution
revenues included in bundled retail rates to energy delivery.
The decrease in revenues is due primarily to a decrease in electricity
trading prices and mild winter weather. In the first quarter of 2002 the AEP
Power Pool grew its electric trading business resulting in a significant
increase in the number of forward electricity contracts entered 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 economic recession. Retail activity for the
period was comparable to that of the same period last year.
Changes in the components 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 supply at higher prices in 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 adjustments to labor force
and contractor support, the latter being converted to an "as needed" versus full
time basis.
The decrease in nonoperating income and expenses was due to a decrease
in power trading revenues and purchases from non-regulated AEP Power Pool
trading transactions outside of the AEP System's traditional marketing area. As
with power trading activity within the traditional marketing areas,
non-regulated trading transactions also experienced declining prices due to
reduced demand and mild weather.
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 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 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)
March 31, 2002 December 31, 2001
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 271,096 $ 271,070
Transmission 371,924 374,116
Distribution 401,798 402,537
General 64,815 65,059
Construction Work in Progress 31,852 15,633
------ ----------
Total Electric Utility Plant 1,141,485 1,128,415
Accumulated Depreciation and Amortization 389,694 384,104
------- -------
NET ELECTRIC UTILITY PLANT 751,791 744,311
------- -------
OTHER PROPERTY AND INVESTMENTS 6,472 6,492
----- -----
LONG-TERM ENERGY TRADING CONTRACTS 134,272 77,972
------- ------
CURRENT ASSETS:
Cash and Cash Equivalents 417 1,947
Accounts Receivable:
Customers 20,762 20,036
Affiliated Companies 29,249 16,012
Miscellaneous 3,937 3,333
Allowance for Uncollectible Accounts (233) (264)
Fuel - at average cost 14,026 12,060
Materials and Supplies - at average cost 15,559 15,766
Accrued Utility Revenues 8,316 5,395
Energy Trading Contracts 198,129 139,605
Prepayments 383 1,314
--- -----
TOTAL CURRENT ASSETS 290,545 215,204
------- -------
REGULATORY ASSETS 98,822 97,692
------ ------
DEFERRED CHARGES 10,334 11,572
------ ------
TOTAL ASSETS $1,292,236 $1,153,243
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2002 December 31, 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) (1,387) (1,903)
Retained Earnings 52,035 48,833
------ ------
Total Common Shareowner's Equity 259,848 256,130
Long-term Debt 236,646 251,093
------- -------
TOTAL CAPITALIZATION 496,494 507,223
------- -------
OTHER NONCURRENT LIABILITIES 11,670 11,929
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 109,500 95,000
Advances from Affiliates 76,794 66,200
Accounts Payable:
General 20,428 24,050
Affiliated Companies 31,797 22,557
Customer Deposits 6,260 4,461
Taxes Accrued 12,015 10,305
Interest Accrued 5,363 5,269
Energy Trading Contracts 199,434 144,364
Other 11,784 12,296
------ ------
TOTAL CURRENT LIABILITIES 473,375 384,502
------- -------
DEFERRED INCOME TAXES 168,086 168,304
------- -------
DEFERRED INVESTMENT TAX CREDITS 10,110 10,405
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 119,222 63,412
------- ------
DEFERRED CREDITS 13,279 7,468
------ -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,292,236 $1,153,243
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 10,246 $7,075
Adjustments for Noncash Items:
Depreciation and Amortization 8,257 8,029
Deferred Federal Income Taxes (556) 4,194
Deferred Investment Tax Credits (295) (297)
Deferred Fuel Costs (net) 1,542 (1,271)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (14,598) 10,227
Fuel, Materials and Supplies (1,759) (350)
Accrued Utility Revenues (2,921) 3,243
Accounts Payable 5,618 3,177
Taxes Accrued 1,710 (3,691)
Mark to Market Energy Contracts (1,858) (5,976)
Change in Other Assets 4,997 (10,086)
Change in Other Liabilities 435 5,871
--- -----
Net Cash Flows From Operating Activities 10,818 20,145
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (15,898) (5,746)
Proceeds from Sales of Property - 216
---- ---
Net Cash Flow Used for Investing Activities (15,898) (5,530)
------- ------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 10,594 (8,033)
Dividends Paid (7,044) (7,561)
------ ------
Net Cash Flows From (Used For) Financing Activities 3,550 (15,594)
----- -------
Net Decrease in Cash and Cash Equivalents (1,530) (979)
Cash and Cash Equivalents at Beginning of Period 1,947 2,270
----- -----
Cash and Cash Equivalents at End of Period $ 417 $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 2001, 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
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
OPCo is a public utility engaged in the generation, sale, purchase,
transmission and distribution of 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 AEP's trading activities are allocated to OPCo 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 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 electricity is in
AEP's traditional marketing area or 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 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 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 energy prices and cost of fuel. Weak wholesale prices, that benefited
our retail sales, resulted in lower margins reducing earnings from wholesale
energy marketing and trading.
The following analyzes the changes in operating 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 allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The decline in revenues is mainly 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 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 March 31,
2002 2001
---- ----
(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 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)
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)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $64,051 $53,397
Adjustments for Noncash Items:
Depreciation 43,196 52,853
Amortization of Transition Assets 19,425 19,256
Deferred Federal Income Taxes (4,649) (1,068)
Amortization of Deferred Property Taxes 14,717 19,992
Mark to Market of Energy Trading Contracts (16,055) (45,268)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (2,618) 1,274
Fuel, Materials and Supplies (6,416) (17,131)
Accrued Utility Revenues (5,368) 264
Prepayments (11,822) (22,537)
Accounts Payable (75,824) (34,942)
Customer Deposits 509 89,622
Taxes Accrued 21,498 (51,420)
Interest Accrued 7,171 11,106
Other Operating Assets 1,388 1,267
Other Operating Liabilities (8,819) (24,848)
------ -------
Net Cash Flows From Operating Activities 40,384 51,817
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (66,312) (65,103)
Proceeds from Sale of Property and Other 154 5,885
--- -----
Net Cash Flows Used For Investing Activities (66,158) (59,218)
------- -------
FINANCING ACTIVITIES:
Change in Advances to Affiliates (net) 89,173 75,950
Retirement of Long-term Debt - (42,506)
Dividends Paid on Common Stock (32,582) (35,744)
Dividends Paid on Cumulative Preferred Stock (314) (314)
---- ----
Net Cash Flows From (Used For) Financing Activities 56,277 (2,614)
------ ------
Net Increase (Decrease) in Cash and Cash Equivalents 30,503 (10,015)
Cash and Cash Equivalents at Beginning of Period 8,848 31,393
----- ------
Cash and Cash Equivalents at End of Period $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 2001, 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
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
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 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
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 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.
Results of Operations
The net loss incurred by PSO increased $0.1 million or 5.6% in 2002
primarily as a result of increased maintenance expense due to storm damage in
2002.
The following analyzes the changes in operating revenues:
Increase (Decrease)
-------------------
(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 decreased as a result of a decline in fuel recovery
revenue and a decline in our share of AEP's marketing and trading operations.
The decrease in electric 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 taxes is predominately due to an increase in
pre-tax income, and changes in certain book/tax timing differences accounted for
on a flow through basis.
Lower interest rates and a reduction in outstanding borrowings caused
the reduction in interest charges.
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 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)
March 31, 2002 December 31, 2001
-------------- -----------------
(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
Paid-in Capital 180,000 180,000
Retained Earnings 118,838 142,994
------- -------
Total Common Shareholder's Equity 456,068 480,224
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 345,205 345,129
------- -------
TOTAL CAPITALIZATION 881,556 905,636
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 106,000 106,000
Advances from Affiliates 186,997 123,087
Accounts Payable - General 46,658 72,759
Accounts Payable - Affiliated Companies 35,531 40,857
Customers Deposits 21,547 21,041
Over-Recovered Fuel Costs 11,100 8,720
Taxes Accrued 27,557 18,150
Interest Accrued 11,365 7,298
Energy Trading Contracts 43,403 167,658
Other 9,637 12,296
----- ------
TOTAL CURRENT LIABILITIES 499,795 577,866
------- -------
DEFERRED INCOME TAXES 299,232 296,877
------- -------
DEFERRED INVESTMENT TAX CREDITS 33,544 33,992
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 38,469 56,203
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 21,160 47,323
------ ------
TOTAL CAPITALIZATION AND LIABILITIES $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)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $(1,648) $ (1,560)
Adjustments for Noncash Items:
Depreciation and Amortization 20,916 19,471
Deferred Income Taxes 1,886 5,750
Deferred Investment Tax Credits (448) (448)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (3,733) (4,018)
Fuel, Materials and Supplies (1,346) 5,864
Accounts Payable (31,427) (35,424)
Taxes Accrued 9,407 4,738
Deferred Property Taxes (21,210) (20,730)
Fuel Recovery 2,380 (2,724)
Mark to Market of Energy Trading Contracts (104) -
Changes in Other Assets 765 (832)
Changes in Other Liabilities (4,235) (3,101)
------ ------
Net Cash Flows Used For Operating Activities (28,797) (33,014)
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (10,559) (28,595)
Other - (359)
----- ----
Net Cash Flows Used For Investing Activities (10,559) (28,954)
------- -------
FINANCING ACTIVITIES:
Retirement of Long-term Debt - (20,000)
Change in Advances From Affiliates (net) 63,910 97,872
Dividends Paid on Common Stock (22,455) (13,060)
Dividends Paid on Cumulative Preferred Stock (53) (53)
--- ---
Net Cash Flows From Financing Activities 41,402 64,759
------ ------
Net Increase in Cash and Cash Equivalents 2,046 2,791
Cash and Cash Equivalents at Beginning of Period 5,795 11,301
----- ------
Cash and Cash Equivalents at End of Period $ 7,841 $ 14,092
======= ========
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 2001,
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
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
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 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
regulators since our electricity supply sales in the Louisiana jurisdiction and
our transmission and distribution operations are cost-based rate-regulated. As a
result of the regulators' 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 regulation 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 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 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 fair value of 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 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 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 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 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 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 revenues. The changes in the
components of revenues 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 natural gas 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 in 2002.
Maintenance expense decreased as a result of costs incurred last year to
restore service and make repairs following a severe ice storm.
The increase in depreciation and amortization expense was due primarily
to the acquisition of the Dolet Hills mining operation.
Income taxes attributable to operations decreased due to a significant
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 2000 and early 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. Also a
decrease in allowance for funds used during construction due to lower
construction balances reduced nonoperating income.
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 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)
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)
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)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 7,190 $ 19,869
Adjustments for Noncash Items:
Depreciation and Amortization 30,140 28,130
Deferred Income Taxes (3,930) (1,930)
Deferred Investment Tax Credits (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) (9,485) 21,669
Fuel, Materials and Supplies (18,504) (662)
Accounts Payable (1,154) (49,324)
Taxes Accrued 26,731 32,119
Deferred Property Taxes (27,217) (24,636)
Fuel Recovery 10,114 (6,637)
Change in Other Assets 19,981 (1,391)
Change in Other Liabilities (2,009) (13,280)
------ -------
Net Cash Flows From (Used For) Operating Activities 22,700 (2,502)
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (11,715) (21,638)
Other - 326
---- ---
Net Cash Flows Used For Investing Activities (11,715) (21,312)
------- -------
FINANCING ACTIVITIES:
Retirement of Long-term Debt (150,450) (450)
Change in Advances from Affiliates (net) 154,959 43,482
Dividends Paid on Common Stock (18,964) (18,553)
Dividends Paid on Cumulative Preferred Stock (57) (57)
--- ---
Net Cash Flows From (Used For) Financing Activities (14,512) 24,422
------- ------
Net Increase (Decrease) in Cash and Cash Equivalents (3,527) 608
Cash and Cash Equivalents at Beginning of Period 5,415 1,907
----- -----
Cash and Cash Equivalents at End of Period $ 1,888 $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 2001,
respectively.
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
--------------------------------------------------------
FIRST QUARTER 2002 vs. FIRST QUARTER 2001
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 to other utilities, municipalities, rural
electric cooperatives and beginning in 2002 to retail electric providers (REPs)
in Texas (see "Introduction of 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 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 SPP (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
utility. During the year 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
is 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 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 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 quarter. 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 $44.2 million due to revenues
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
Trading 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 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
ERCOT transmission-related fees.
Income taxes attributable to operations increased due to a significant
increase in pre-tax income.
A decrease in nonoperating income was caused 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 AEP Affiliates 50,242 6,023
------ -----
Total Operating Revenues 141,236 195,006
------- -------
OPERATING EXPENSES:
Fuel 24,980 59,905
Purchased Power:
Electricity Marketing and Trading 44,123 61,300
AEP Affiliates 11,650 20,392
Other Operation 24,170 25,756
Maintenance 4,356 4,562
Depreciation and 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)
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)
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)
Three Months Ended March 31,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 3,992 $ 891
Adjustments for Noncash Items:
Depreciation and Amortization 11,569 11,771
Deferred Income Taxes (226) 85
Deferred Investment Tax Credits (318) (318)
Mark-to-Market of Energy Trading Contracts (664) (2,129)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (28,456) 12,381
Fuel, Materials and Supplies (906) (1,051)
Accounts Payable (949) (15,986)
Taxes Accrued 4,205 5,044
Fuel Recovery (628) (1,843)
Deferred Property Taxes (9,525) (8,616)
Change in Other Assets (4,118) 3,049
Change in Other Liabilities (288) 2,281
---- -----
Net Cash Flows From (Used For) Operating Activities (26,312) 5,559
------- -----
INVESTING ACTIVITIES:
Construction Expenditures (7,531) (10,762)
Other - -
---- ------
Net Cash Flows Used For Investing Activities (7,531) (10,762)
------ -------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 38,720 9,238
Dividends Paid on Common Stock (6,749) (7,206)
Dividends Paid on Cumulative Preferred Stock (26) (26)
--- ---
Net Cash Flows From (Used For) Financing Activities 31,945 2,006
------ -----
Net Decrease in Cash and Cash Equivalents (1,898) (3,197)
Cash and Cash Equivalents at Beginning of Period 2,454 6,941
----- -----
Cash and Cash Equivalents at End of Period $ 556 $ 3,744
===== =======
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
2001, respectively.
See Notes to Financial Statements beginning on page L-1.
NOTES 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. Goodwill and Other
Intangible Assets AEP
3. Acquisitions and
Dispositions AEP
4. Rate Matters AEP, WTU
5. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, SWEPCo, WTU
6. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
7. Financing and Related
Activities AEP, CPL, SWEPCo
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 2001 Annual Report as incorporated in and filed
with the Form 10-K.
Certain prior period financial statement items were reclassified
to conform to current period presentation. Reclassifications had no
effect on previously 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. GOODWILL AND OTHER INTANGIBLE ASSETS
SFAS 142, "Goodwill and Other 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 adoption of SFAS 142 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 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 DISPOSITIONS
In January 2002 AEP acquired for $2 million the existing
trading operations, including 34 key staff, of Enron's Norway and
Sweden-based energy trading businesses. The acquisition is an addition
to the growing energy trading operation in Europe 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 net assets acquired is approximately $2
million which is recorded as goodwill. The allocation of the purchase
price is subject to revision after completion of a final appraisal of
the fair values of the assets acquired and liabilities assumed.
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 market 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 transaction is contingent upon the
fair market value appraisal meeting the required contractual
guidelines, regulatory approval from the PUCT and federal anti-trust
clearance. AEP and Centrica expect to complete the regulatory approval
process and conclude the transaction by the end of 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 Retail 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 the 2001 Annual Report, on January 1, 2002,
customer choice of electricity supplier began in the ERCOT area of
Texas. Customer choice has been delayed in other areas of Texas
including the SPP area. 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 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 company, a transmission and distribution utility and a retail
electric provider.
Due to the delay in the start of competition in the SPP area and
lack of regulatory approval for our corporate separation plan, only
CPL's and WTU's retail electric providers commenced operations on
January 1, 2002. Operations for 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. The transition notes provide more economical
financing for certain transition generation related regulatory assets
during their 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. The Texas Legislation allows
for several alternative methods to be used to value stranded costs in
the final 2004 true-up proceeding including the sale of and/or exchange
of generation assets, the issuance of power generation company stock to
the 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, the additional amount recoverable can also be
securitized.
The PUCT ordered 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 cost. Final stranded cost amounts and the treatment of
excess earnings will be determined in the 2004 true-up proceeding. The
PUCT currently estimates that CPL will have no stranded cost and has
ordered the rate reduction to return excess earnings, pending the
outcome of the 2004 true-up proceeding. Since CPL expensed excess
earnings amounts in 1999, 2000, and 2001, the order has no additional
effect on reported net income but will reduce cash flows for the five
year refund period.
Beginning January 1, 2002, fuel costs for CPL and WTU in ERCOT
are no longer subject to PUCT fuel reconciliation proceedings.
Consequently, CPL and WTU will file a final fuel reconciliation with the
PUCT which reconciles their fuel costs through the period ending
December 31, 2001. These final fuel balances will be included in each
company's 2004 true-up proceeding. The elimination of the fuel clause
recoveries in 2002 in Texas will subject AEP, CPL and WTU to the 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 have a
material adverse effect on results of operations, cash flows and
possibly financial condition.
Michigan Restructuring - Affecting AEP and I&M
Customer choice commenced 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 has 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 has not yet discontinued regulatory accounting under SFAS 71.
6. BUSINESS SEGMENTS
AEP has three business segments: Wholesale, Energy Delivery and
Other. The business activities of each of these segments are as follows:
Wholesale
o Generation of electricity for sale to retail and wholesale customers,
o Marketing and trading of electricity and gas worldwide.
o Gas pipeline and storage services and other energy supply related
business
o Coal mining, bulk commodity barging operations and other energy
supply related businesses
Energy Delivery
o Domestic electricity transmission
o Domestic electricity distribution
Other
o Foreign electricity distribution and supply investments
o Telecommunication services
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)
Revenues from:
External customers $12,115 $ 798 $ 501 $ - $13,414
Other operating segments 658 1 243 (902) -
Segment EBIT 238 204 65 - 507
Total assets 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 Revenues from:
External customers 12,878 789 568 - 14,235
Other operating segments 192 (192)
Segment EBIT 352 245 113 (5) 705
Total assets 25,392 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.
Three Months Ended Three Months Ended
March 31, 2002 March 31, 2001
Revenues Revenues
From From
External Segment External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
Wholesale Segment (in thousands) (in thousands)
APCo $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 External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
Energy Delivery Segment (in thousands) (in thousands)
APCo $154,995 $58,694 $2,448,468 $152,097 $63,189 $2,906,810
CPL 112,127 26,527 2,098,569 110,330 32,372 2,072,634
CSPCo 102,548 11,688 1,234,685 98,996 14,762 1,333,956
I&M 74,537 35,321 1,618,241 77,937 36,114 1,704,121
KPCo 35,129 16,500 635,780 36,327 16,636 701,388
OPCo 141,760 23,943 1,924,868 131,849 34,077 2,019,304
PSO 51,732 5,263 934,769 48,417 6,344 945,599
SWEPCo 68,935 13,633 1,189,595 78,057 24,660 1,058,616
WTU 40,629 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 $1,455,156 $117,681 $5,552,082 $1,974,127 $125,955 $6,591,405
CPL 403,223 66,073 5,020,501 603,412 84,452 5,018,484
CSPCo 949,315 66,303 3,429,680 1,125,573 74,925 3,958,327
I&M 1,038,759 40,068 5,203,347 1,291,538 75,847 5,876,280
KPCo 351,308 22,257 1,292,236 459,157 17,657 1,541,511
OPCo 1,383,586 124,416 5,376,727 1,699,665 103,313 6,213,244
PSO 247,850 6,326 1,773,756 356,139 7,057 1,790,907
SWEPCo 330,748 23,270 2,332,540 425,689 41,880 2,205,451
WTU 141,236 11,226 915,387 195,006 6,994 928,719
7. FINANCING AND RELATED ACTIVITIES
In 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 retire 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 quarter of 2002 by the registrant subsidiaries:
Principal
Type Amount Interest Due
Company of Debt Retired Rate Date
------- ------- ----------- -------- ----
(in millions) (%)
CPL Senior Unsecured Notes $150 Variable 2002
SWEPCo Senior Unsecured Notes 150 Variable 2002
Non-Registrant AEP Subs. Notes Payable 12 Variable 2002-2007
----
$312
8. CONTINGENCIES
Litigation
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo,
CSPCo, I&M, and OPCo
As discussed in Note 8 of the Notes 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
APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities made
modifications to generating units at coal-fired generating plants in
violation of the Clean Air Act. Federal EPA filed complaints against AEP
subsidiaries in U.S. District Court for the Southern District of Ohio. A
separate lawsuit initiated by certain special interest groups was
consolidated with the Federal EPA case. The alleged modification of the
generating units occurred over a 20 year period.
Under the Clean Air Act, if a plant undertakes a major
modification that directly results in an emissions increase, permitting
requirements might be triggered and the plant may be required to install
additional pollution control technology. This requirement does not apply
to activities such as routine maintenance, replacement of degraded
equipment or failed components, or other repairs needed for the
reliable, safe and efficient operation of the plant. The Clean Air Act
authorizes civil penalties of up to $27,500 per day per violation at
each generating unit ($25,000 per day prior to January 30, 1997). In
2001 the 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 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 unless such
costs can be recovered through regulated rates and market prices for
electricity.
In December 2000 Cinergy Corp., an unaffiliated utility, which
operates certain plants jointly owned by CSPCo, reached a tentative
agreement with Federal EPA and other parties to settle litigation
regarding generating plant emissions under the Clean Air Act.
Negotiations are continuing between the parties in an attempt to reach
final settlement terms. Cinergy's settlement could impact the operation
of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4%
and 12.5%, respectively, by CSPCo). Until a final settlement is reached,
CSPCo will be unable to determine the settlement's impact on its jointly
owned facilities and its future results of operations and cash flows.
NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo
and SWEPCo
Federal EPA issued a NOx Rule requiring substantial reductions in
NOx emissions in a number of eastern states, including certain states in
which the AEP System's generating plants are located. The NOx Rule has
been upheld on appeal. The compliance date for the NOx Rule is May 31,
2004.
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 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 assumption 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. Affected utilities including certain AEP
operating companies, petitioned the D.C. Circuit Court to review the
Section 126 Rule.
After review, the D.C. Circuit Court instructed Federal EPA to
justify the methods it used to allocate allowances and project growth
for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and
other utilities requested that the D.C. Circuit Court vacate the Section
126 Rule or suspend its May 2003 compliance date. In August 2001 the
D.C. Circuit Court issued an order tolling the compliance schedule until
Federal EPA responds to the Court's remand. On April 30, 2002, Federal
EPA announced that May 31, 2004 is the compliance date for the Section
126 Rule. Federal EPA published a notice in the Federal Register on May
1, 2002 advising that no changes in the growth factors used to set the
NOx budgets were warranted.
In 2000 the Texas Natural Resource Conservation Commission
adopted rules requiring significant reductions in NOx emissions from
utility sources, including CPL and SWEPCo. The compliance date is May
2003 for CPL and May 2005 for SWEPCo.
AEP is installing selective catalytic reduction (SCR) technology
to reduce NOx emission. During 2001 SCR on OPCo's Gavin Plant commenced
operations. Installation of SCR technology on Amos and Mountaineer
plants was completed and commenced operation in May 2002. Construction
of SCR technology at certain other AEP generating units continues with
completion scheduled in May 2003 through 2006.
Our estimates indicate that AEP's compliance with the NOx Rule,
the Texas Natural Resource Conservation Commission rule and the Section
126 Rule could result in required capital expenditures of approximately
$1.6 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
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 2001 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 for AEP and its
registrant subsidiaries. Management's discussion and analysis of results of
operations for AEP and each of its registrant subsidiaries for the quarter ended
March 31, 2002 is presented with their financial statements earlier 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,
preferred stock or long-term debt and sale-leaseback or leasing agreements. We
operate a money pool and sell accounts receivables to provide liquidity for the
domestic electric subsidiaries. Short-term borrowings are supported by a
bank-sponsored receivables purchase agreement, a term loan facility and three
revolving credit agreements.
During the first quarter of 2002 cash flow from operations was negative
$14 million, including $181 million from net income and $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 issuance of $797 million of transition funding bonds provided
funds to cover the operating funds deficiency, reduce debt, fund construction
and pay dividends. Major construction expenditures included amounts for emission
control technology on several coal-fired generating units (see discussion in
Note 8).
During the fourth quarter of 2001, Quaker Coal Co., MEMCO Barge Line,
Inc. and two coal-fired generating plants in the UK were acquired using
short-term borrowings and available cash. Long-term financing arrangements are
being negotiated for the UK generating plants and will be announced as
completed. Completion of this financing is anticipated in the second quarter of
2002. Long-term funding arrangements are often complex and 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 first quarter period were $354 million. The following table shows the
plant and property additions by certain registrant subsidiaries:
Company Amount
------- ------
(in millions)
APCo $63
CPL 21
I&M 27
OPCo 66
SWEPCo 12
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
As discussed in the 2001 Annual Report, we have filed with the FERC and
SEC seeking approval to separate our regulated and unregulated operations. Our
plan for corporate separation allows us to meet the requirements of Texas and
Ohio restructuring legislation. We 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. We proposed amendments to 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 will be
required to retire various debt securities and to transfer assets between legal
entities.
RTO Formation
As discussed in the 2001 Annual Report, FERC Order No. 2000 and many of
the settlement agreements with the state regulatory commissions to approve the
AEP-CSW merger required the transfer of control of our transmission system to an
RTO. Certain AEP subsidiaries participated in the formation of the Alliance RTO.
Other subsidiaries are members of ERCOT or SPP.
The FERC expressed its opinion that large RTOs will better support
competition and reliability of electric service. In May 2002 AEP announced an
agreement with the PJM Interconnection to pursue terms for participation in its
RTO. Final agreements are expected to be negotiated.
Management is unable to predict the outcome of these transmission
regulatory actions and proceedings or their impact on the timing and operation
of RTOs, our transmission operations or results of operations and cash flows.
OTHER MATTERS
Industry Restructuring
As discussed in Note 5 and the 2001 Annual Report, restructuring and
customer choice began in four of the eleven state retail jurisdictions in which
the AEP electric utility companies operate. Restructuring legislation provides
for a transition from cost-based regulation of bundled electric service to
customer choice and market pricing for the supply of electricity. Customer
choice of electricity supplier began on January 1, 2001 for Ohio customers and
on January 1, 2002, for Michigan, Texas and Virginia customers. In Ohio,
Michigan and Virginia virtually all customers continue to receive electric
generation, transmission and distribution services from our electric operating
companies.
In the Texas jurisdiction competition began in the ERCOT area but was
delayed in the SPP area.
In 2001 the PUCT issued an order requiring CPL to reduce future
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 cost. Final stranded cost amounts and the treatment of excess
earnings will be determined in the 2004 true-up proceeding. The PUCT currently
estimates that CPL will have no stranded cost and has ordered the rate reduction
to return excess earnings, pending the outcome of the 2004 true-up proceeding.
CPL expensed excess earnings amounts in 1999, 2000 and 2001. Consequently, the
order has no effect on reported net income.
Beginning January 1, 2002, fuel costs are no longer subject to PUCT
fuel reconciliation proceedings under the Texas Restructuring Legislation.
Consequently, CPL and WTU will file a final fuel reconciliation with the PUCT to
reconcile their fuel costs through the period ending December 31, 2001. These
final fuel balances will be included in each company's 2004 true-up proceeding.
The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP,
CPL and WTU to the risk of fuel market price increases and could adversely
affect future results of operations beginning in 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. Litigation Federal EPA Complaint
and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo
As discussed 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 APCo, CSPCo,
I&M, OPCo and eleven unaffiliated utilities made modifications to generating
units at coal-fired generating plants in violation of the Clean Air Act. Federal
EPA filed complaints against AEP subsidiaries in U.S. District Court for the
Southern District of Ohio. A separate lawsuit initiated by certain special
interest groups was consolidated with the Federal EPA case. The alleged
modification of the generating units occurred over a 20 year period.
Under the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed components, or other
repairs needed for the reliable, safe and efficient operation of the plant. The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit ($25,000 per day prior to January 30, 1997). In 2001 the
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.
Management is unable to estimate the loss or range of loss related to
the contingent liability for civil penalties under the Clear Air Act proceedings
and unable to predict the timing of resolution of these matters due to the
number of alleged violations and the significant number of issues yet to be
determined by the Court. In the event the AEP System companies do not prevail,
any capital and operating costs of additional pollution control equipment that
may be required as well as any penalties imposed would adversely affect future
results of operations, cash flows and possibly financial condition unless such
costs can be recovered through regulated rates and market prices for
electricity.
In December 2000 Cinergy Corp., an unaffiliated utility, which operates
certain plants jointly owned by CSPCo, reached a tentative agreement with
Federal EPA and other parties to settle litigation regarding generating plant
emissions under the Clean Air Act. Negotiations are continuing between the
parties in an attempt to reach final settlement terms. Cinergy's settlement
could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station
Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement
is reached, CSPCo will be unable to determine the settlement's impact on its
jointly owned facilities and its future results of operations and cash flows.
NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and
SWEPCo
Federal EPA issued a NOx Rule requiring substantial reductions in NOx
emissions in a number of eastern states, including certain states in which the
AEP System's generating plants are located. The NOx Rule has been upheld on
appeal. The compliance date for the NOx Rule is May 31, 2004.
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 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 assumption
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. Affected
utilities including certain AEP operating companies, petitioned the D.C. Circuit
Court to review the Section 126 Rule.
After review, the D.C. Circuit Court instructed Federal EPA to justify
the methods it used to allocate allowances and project growth for both the NOx
Rule and the Section 126 Rule. AEP subsidiaries and other utilities requested
that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003
compliance date. In August 2001 the D.C. Circuit Court issued an order tolling
the compliance schedule until Federal EPA responds to the Court's remand. On
April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date
for the Section 126 Rule. Federal EPA published a notice in the Federal Register
on May 1, 2002 advising that no changes in the growth factors used to set the
NOx budgets were warranted.
In 2000 the Texas Natural Resource Conservation Commission adopted rules
requiring significant reductions in NOx emissions from utility sources,
including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005
for SWEPCo.
AEP is installing selective catalytic reduction (SCR) technology to
reduce NOx emission. During 2001 SCR on OPCo's Gavin Plant commenced operations.
Installation of SCR technology on Amos and Mountaineer plants was completed and
commenced operation in May 2002. Construction of SCR technology at certain other
AEP generating units continues with completion scheduled in May 2003 through
2006.
Our estimates indicate that AEP's compliance with the NOx Rule, the
Texas Natural Resource Conservation Commission rule and the Section 126 Rule
could result in required capital expenditures of approximately $1.6 billion,
including amounts spent through March 31, 2002.
The following table shows the estimated compliance cost for certain of
AEP's 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 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.
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 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
changes in the underlying market prices or rates.
Policies and procedures have been established to identify, assess, and
manage market risk exposures in our day to day operations. Our risk policies
have been reviewed with the Board of Directors, approved by a Risk 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 use 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 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 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.
AEP is exposed to risk from changes in the market prices of coal and
natural gas used to generate electricity where generation is no longer regulated
or where existing fuel clauses are suspended or frozen. The protection afforded
by fuel clause recovery mechanisms has either been eliminated by the
implementation of customer choice in Ohio (effective January 1, 2001 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 market price risk. AEP
continues to be protected against market price changes by active fuel clauses in
Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.
We employ physical forward purchase and sale contracts, exchange futures
and options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. 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. The
amount of risk taken by the traders is controlled by the management of the
trading operations and the Company's Chief Risk Officer 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 hedges, cash flow hedges and swaps to mitigate
changes in interest rates or fair values on short and long-term debt when
management deems it necessary. We do not hedge all interest rate risk.
We employ cash flow forward hedge contracts to lock-in prices on
transactions denominated in foreign currencies where deemed necessary.
International subsidiaries use currency swaps to hedge exchange rate
fluctuations in debt denominated in foreign currencies. We do not hedge all
foreign currency exposure.
AEP limits credit risk by extending 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 requires cash deposits, letters of credit and
parental/affiliate guarantees as security from certain below investment grade
counterparties in our normal course of business.
We trade electricity and gas contracts with numerous counterparties.
Since our open energy trading contracts are valued based on changes in market
prices of the related commodities, our exposures change daily. We believe that
our credit and market exposures with any one counterparty is not material 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 the contractual price. The following table approximates
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 registrant
subsidiaries is generally consistent with that of AEP.
We enter into transactions for electricity and natural gas as
part of wholesale trading operations. Electric and gas transactions 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
counterparties 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 December 31, 2001 were $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
---- ----
(in millions) (in millions)
Energy 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) -
--- ---
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 fair 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 reflected in the income statement for those
companies that operate in regulated jurisdictions; and deferrals of
option 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 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
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
Vice President and Controller and Chief Accounting Officer
Treasurer
Date: May 13, 2002