UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended JUNE 30, 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 July 31, 2002 was 338,835,220.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended June 30, 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-5
Consolidated Financial Statements A-6 - A-10
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-16
Item 2. Registrants' Combined Management Discussion and Analysis of
Financial Condition, Contingencies and Other Matters M-1 - M-11
Item 3. Quantitative and Qualitative Disclosures About Market Risk N-1 - N-9
Part II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders O-1
Item 5. Other Information O-3
Item 6. Exhibits and Reports on Form 8-K O-4
(a) Exhibits
Exhibit 3 (d)
Exhibit 3 (e)
Exhibit 12
Exhibit 99.1
Exhibit 99.2
(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.
----------------------
SFAS 142........................... Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.
-------------------------------------
SFAS 144........................... Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or
--------------------------------
Disposal of Long-lived Assets.
-----------------------------
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 Liquidity in the wholesale markets
o Other risks and unforeseen events.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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
Net income for the second quarter was $62 million or $0.19 per share, a
decrease of $170 million or $0.53 per share. AEP had a loss of $107 million
($0.33 per share) year-to-date compared with net income of $498 million ($1.54
per share) in 2001. A decline in system sales and margins, natural gas trading
losses and charges associated with the impairment and divesture of foreign
retail electricity and gas supply and distribution operations account for the
decrease.
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. A recently issued accounting
pronouncement will require us to report our trading transactions on a net basis
beginning in the third quarter of 2002. Our adoption of this new standard will
lead to a material decrease in both revenues and purchased energy expense. See
"New Accounting Standard" section in Registrants' Combined Management Discussion
and Analysis of Financial Condition, Contingencies and Other Matters.
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.
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 About 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 second quarter of 2002 decreased by $170 million and
by $605 million year-to-date. Reduced margins resulting from lower wholesale
energy prices, losses from gas trading and marketing and losses associated with
the impairment and divesture of SEEBOARD in the UK and CitiPower in Australia,
two foreign retail electricity and gas supply and distribution investments,
account for the decreases. In 2002 the wholesale energy sector has been under
pressure from lower commodity prices in contrast to last year when we had strong
performance from the wholesale business due to favorable market conditions. Also
contributing to the year-to-date decrease was a transitional goodwill impairment
loss related to SEEBOARD and CitiPower from the adoption of SFAS 142 (see Note
2) that has been reported as a cumulative effect of an accounting change
retroactive to January 1, 2002.
The rise in revenues from gas marketing and trading can be attributed to
an increase in gas marketing and trading volume, up 123% year-to-date, as we
expanded our gas trading operations around Houston Pipe Line (HPL) that we
acquired in June 2001. Gas marketing and trading volume also rose in the second
quarter as the Company continued unwinding positions that led to a first-quarter
gas trading loss. The decrease in electric marketing and trading revenues was
largely driven by the decline in system sales due to lower wholesale energy
prices that decreased margins.
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
And Trading* $ (558) (6) $(1,306) (7)
Gas Marketing and Trading 1,289 36 1,274 18
Energy Delivery* 13 1 22 1
Other Investments 20 18 8 3
------ -------
Total $ 764 5 $ (2) -
====== =======
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The changes in the total expenses were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel and Purchased Energy:
Electricity Marketing
And Trading $ (967) (11) $(1,899) (11)
Gas Marketing and Trading 1,528 45 1,663 24
Other Investments 24 46 61 59
Maintenance and Other Operation 423 47 519 29
Depreciation and Amortization 38 12 68 11
Taxes other Than Income Taxes 9 5 27 8
------ ------
$1,055 8 $ 439 2
====== ======
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 second quarter of 2001. Net
generation decreased 1.2% 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 and 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 an expansion of gas trading activity around our HPL pipeline
assets.
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; the expenses of recently acquired businesses
MEMCO, a barging line; Quaker Coal; and two power plants in the UK; and a charge
associated with the impairment and divestiture of CitiPower, a retail
electricity and gas supply and distribution subsidiary in Australia. 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. On July 19, 2002, AEP, through a wholly owned
subsidiary entered into an agreement to sell CitiPower, and recorded a net
impairment charge totaling $125 million. $163 million (excluding tax of $65
million) was recorded in operating expenses in the second quarter of 2002 (see
Note 3). $27 million of net impairment loss has been classified as a
transitional goodwill impairment loss from the adoption of SFAS 142 (see Note 2)
and has been recorded as a cumulative effect of an accounting change retroactive
to January 1, 2002.
Other income decreased due to the gain from the sale of Frontera in
2001.
The decrease in income taxes is predominately due to a decrease in
pre-tax income.
The decrease in interest was primarily due to 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 Six Months Ended
June 30, June 30,
2002 2001 2002 2001
---- ---- ---- ----
REVENUES:
Electricity Marketing and Trading $9,001 $9,559 $17,525 $18,831
Gas Marketing and Trading 4,886 3,597 8,477 7,203
Domestic Electric Delivery 896 883 1,694 1,672
Other Investments 129 109 246 238
------- ------- ------- -------
TOTAL REVENUES 14,912 14,148 27,942 27,944
------- ------- ------- -------
EXPENSES:
Fuel and Purchased Energy:
Electricity Marketing and Trading 7,757 8,724 15,046 16,945
Gas Marketing and Trading 4,929 3,401 8,602 6,939
Other Investments 76 52 165 104
------- ------- ------- -------
TOTAL FUEL AND PURCHASED ENERGY 12,762 12,177 23,813 23,988
------- ------- ------- -------
Maintenance and Other Operation 1,332 909 2,325 1,806
Depreciation and Amortization 367 329 710 642
Taxes Other Than Income Taxes 178 169 364 337
------- ------- ------- -------
TOTAL EXPENSES 14,639 13,584 27,212 26,773
------- ------- ------- -------
OPERATING INCOME 273 564 730 1,171
OTHER INCOME 46 101 63 154
OTHER EXPENSE 7 28 29 47
LESS: INTEREST 204 217 414 464
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 3 2 5 5
MINORITY INTEREST IN FINANCE SUBSIDIARY 9 - 18 . -
------- ------- ------- -------
INCOME BEFORE INCOME TAXES 96 418 327 809
INCOME TAXES 38 163 120 321
------- ------- ------- -------
INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS,
EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A
CHANGE IN ACCOUNTING PRINCIPLE 58 255 207 488
Discontinued Operations (net of tax) 4 25 36 58
Extraordinary Loss - (net of tax) - (48) - (48)
Cumulative Effect of Goodwill Transition
Impairment - - (350) -
------- ------- ------- -------
NET INCOME (LOSS) $ 62 $ 232 $ (107) $ 498
======= ======= ======== =======
AVERAGE NUMBER OF SHARES OUTSTANDING 326 322 324 322
=== === === ===
EARNINGS (LOSS) PER SHARE (BASIC AND DULUTIVE):
Income Before Discontinued Operations,
Extraordinary Item and Cumulative Effect of a
Change in Accounting Principle $ 0.18 $ 0.79 $ 0.64 $1.51
Discontinued Operations 0.01 0.08 0.11 0.18
Extraordinary Loss - (0.15) - (0.15)
Cumulative Effect of a Change in Accounting
Principle - - (1.08) -
------ ------ ------ -----
EARNINGS (LOSS) PER SHARE (BASIC AND DILUTIVE) $ 0.19 $ 0.72 $(0.33) $1.54
====== ====== ====== =====
CASH DIVIDENDS PAID PER SHARE $0.60 $0.60 $1.20 $1.20
===== ===== ===== =====
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2002 December 31, 2001
(in millions)
ASSETS
- ------
CURRENT ASSETS:
Cash and Cash Equivalents $ 585 $ 244
Accounts Receivable (net) 2,638 1,687
Fuel, Materials and Supplies 1,146 1,048
Energy Trading and Derivative Contracts 9,466 8,572
Other 1,276 688
------- -------
TOTAL CURRENT ASSETS 15,111 12,239
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 18,090 17,477
Transmission 5,971 5,879
Distribution 9,827 9,661
Other (including gas, coal mining and
nuclear fuel) 4,086 4,597
Construction Work in Progress 1,274 1,102
------- -------
Total Property, Plant and Equipment 39,248 38,716
Accumulated Depreciation and Amortization 15,807 15,456
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 23,441 23,260
------- -------
REGULATORY ASSETS 2,314 3,162
------- -------
SECURITIZED TRANSITION ASSET 751 -
------- -------
INVESTMENTS IN POWER, DISTRIBUTION AND
COMMUNICATIONS PROJECTS 540 633
------- -------
ASSETS HELD FOR SALE 2,750 2,832
------- -------
GOODWILL 482 417
------- -------
INTANGIBLE ASSETS 366 474
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 3,672 2,370
------- -------
OTHER ASSETS 1,731 1,894
------- -------
TOTAL $51,158 $47,281
======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2002 December 31, 2001
------------- -----------------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 2,641 $ 1,985
Short-term Debt 3,041 4,011
Long-term Debt Due Within One Year 1,506 1,114
Energy Trading And Derivative Contracts 9,538 8,311
Other 1,789 1,926
------- -------
TOTAL CURRENT LIABILITIES 18,515 17,347
-------- -------
LONG-TERM DEBT 10,094 9,052
------- -------
EQUITY UNIT SENIOR NOTES 376 -
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 3,444 2,183
------- -------
DEFERRED INCOME TAXES 4,326 4,555
------- -------
DEFERRED INVESTMENT TAX CREDITS 474 491
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 863 871
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 190 194
------- -------
OTHER NONCURRENT LIABILITIES 1,321 1,334
------- -------
LIABILITIES HELD FOR SALE 1,955 1,798
------- -------
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 145 156
------- -------
COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
2002 2001
---- ----
Shares Authorized. . .600,000,000 600,000,000
Shares Issued. . . . .347,833,712 331,234,997
(8,999,992 shares were held in treasury at
June 30, 2002 and December 31, 2001) 2,261 2,153
Paid-in Capital 3,413 2,906
Accumulated Other Comprehensive Income (Loss) (92) (126)
Retained Earnings 2,802 3,296
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 8,384 8,229
------- -------
TOTAL $51,158 $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)
Six Months Ended June 30,
2002 2001
---- ----
(in millions)
OPERATING ACTIVITIES:
Net Income (Loss) $ (107) $ 498
Adjustments for Noncash Items:
Depreciation and Amortization 710 664
Deferred Federal Income Taxes (111) 11
Deferred Investment Tax Credits (10) (17)
Amortization of Deferred Property Taxes 35 82
Amortization of Cook Plant Restart Costs 20 20
Deferred Costs Under Fuel Clause Mechanisms (35) 50
Transitional Impairment of Goodwill 350 -
Provision for Loss on CitiPower 98 -
Discontinued Operations (36) (58)
Extraordinary Loss - Effects of Deregulation - 48
Mark to Market on Open Energy Trading Contracts (87) (260)
Realized Mark to Market on Settled Energy Trading Contracts 294 (5)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (941) (1,205)
Fuel, Materials and Supplies 250 (108)
Accrued Utility Revenues (182) (84)
Prepayments and Other (73) 1
Accounts Payable 354 (1,643)
Taxes Accrued (15) 53
Interest Accrued 57 48
Option Premiums 49 (161)
Change in Other Assets (841) 2,694
Change in Other Liabilities 317 (63)
------- -------
Net Cash Flows From Operating Activities 96 565
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (783) (812)
Purchase of Houston Pipe Line - (727)
Sale of Yorkshire - 383
Sale of Frontera - 265
Other (21) (97)
------- -------
Net Cash Flows Used For Investing Activities (804) (988)
------- -------
FINANCING ACTIVITIES:
Issuance of Common Stock 656 9
Issuance of Long-term Debt 1,786 1,388
Issuance of Equity Unit Senior Notes 334 -
Change in Short-term Debt (net) (970) (275)
Retirement of Long-term Debt (357) (463)
Dividends Paid on Common Stock (387) (387)
------- -------
Net Cash Flows From Financing Activities 1,062 272
------- -------
Effect of Exchange Rate Change on Cash (13) -
------- -------
Net Increase (Decrease) in Cash and Cash Equivalents 341 (151)
Cash and Cash Equivalents at Beginning of Period 244 363
------- -------
Cash and Cash Equivalents at End of Period $ 585 $ 212
======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $335 million and $342
million and for income taxes was $307 million and $107 million in 2002 and 2001,
respectively. Noncash acquisitions under capital leases were $2 million in 2002
and $21 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 1 8 9
Common Stock Dividends (387) (387)
Other (7) 9 2
------
7,678
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes
Currency Translation Adjustment (53) (53)
Unrealized Gain on
Hedged Derivative 31 31
Minimum Pension Liability (6) (6)
Net Income 498 498
------
Total Comprehensive Income 470
------ ------ ------ ----- ------
JUNE 30, 2001 $2,153 $2,916 $3,210 $(131) $8,148
====== ====== ====== ===== ======
JANUARY 1, 2002 $2,153 $2,906 $3,296 $(126) $8,229
Issuance of Common Stock 108 568 676
Common Stock Dividends (387) (387)
Other (61) (61)
------
8,457
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes
Currency Translation Adjustment 73 73
Unrealized Loss on Cash Flow
Hedges (39) (39)
Net Income (Loss) (107) (107)
-------
Total Comprehensive Income (73)
------ ------ ------ ---- ------
JUNE 30, 2002 $2,261 $3,413 $2,802 $(92) $8,384
====== ====== ====== ==== ======
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 $345,000 or 17% for the second quarter and $432,000
or 11% for the year-to-date period due to limits on recovery of return on
capital related to operating and in-service ratios of the Rockport Plant.
Increased recoverable operating expenses resulted in a $1,139,000
increase in operation revenues for the second quarter. A decrease in operating
revenues of $9,493,000 for the year-to-date period 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 the first quarter of 2002 decreased Rockport Plant's generation.
Operating expenses increased 3% in the second quarter and declined 8%
for the year-to-date period as follows:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
-------------- ------------
(in thousands) % (in thousands) %
-------------- - -------------- -
Fuel $1,274 6 $(8,871) (19)
Rent - Rockport Plant Unit 2 - - - -
Other Operation 1,646 70 1,910 36
Maintenance (1,593) (40) (543) (9)
Depreciation 40 1 87 1
Taxes Other Than Income Taxes (118) (12) (108) (5)
Income Taxes 268 N.M. (1,550) (62)
------ -------
Total $1,517 3 $(9,075) (8)
====== =======
N.M. = Not Meaningful
Fuel expense increased in the second quarter due to an increase in
generation and decreased due to the decline in generation for the year-to-date
period.
The increases in other operation expense are primarily due to
higher costs for employee benefits and property insurance.
Maintenance expense decreased significantly in the second quarter due
to scheduled boiler inspection and repair being in the first quarter 2002
verses second quarter 2001. Maintenance costs declines in both periods
reflect cost control efforts.
The decrease in income taxes attributable to operations for the
year-to-date period is primarily due to an over-accrual of state income taxes
during first quarter of 2001 based on an estimate of higher taxable income for
the year 2001 than actually occurred. The over-accrual was adjusted
beginning in the second quarter of 2001 resulting in higher comparable income
taxes for the second quarter of 2002.
Interest charges declined 23% in the second quarter and 11% for the
year-to-date period due to lower interest rates on short-term borrowing through
AEP's money pool reflecting market conditions and lower outstanding balances.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES - Sales to
AEP Affiliates $53,356 $52,217 $103,231 $112,724
------- ------- -------- --------
OPERATING EXPENSES:
Fuel 21,535 20,261 39,035 47,906
Rent - Rockport Plant Unit 2 17,070 17,070 34,141 34,141
Other Operation 4,014 2,368 7,236 5,326
Maintenance 2,378 3,971 5,354 5,897
Depreciation 5,642 5,602 11,275 11,188
Taxes Other Than Income Taxes 907 1,025 1,960 2,068
Income Taxes 306 38 959 2,509
------- ------- -------- --------
TOTAL OPERATING EXPENSES 51,852 50,335 99,960 109,035
------- ------- -------- --------
OPERATING INCOME 1,504 1,882 3,271 3,689
NONOPERATING INCOME 32 - 34 -
NONOPERATING EXPENSES 94 1 106 10
NONOPERATING INCOME TAX CREDITS 823 888 1,655 1,759
INTEREST CHARGES 547 706 1,243 1,395
------- ------- -------- -------
NET INCOME $ 1,718 $ 2,063 $ 3,611 $ 4,043
======= ======= ======== =======
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $14,604 $10,743 $13,761 $ 9,722
NET INCOME 1,718 2,063 3,611 4,043
CASH DIVIDENDS DECLARED 1,050 959 2,100 1,918
------- ------- ------- -------
BALANCE AT END OF PERIOD $15,272 $11,847 $15,272 $11,847
======= ======= ======= =======
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)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $641,903 $638,297
General 2,883 3,012
Construction Work in Progress 10,993 6,945
-------- --------
Total Electric Utility Plant 655,779 648,254
Accumulated Depreciation 349,825 337,151
-------- --------
NET ELECTRIC UTILITY PLANT 305,954 311,103
-------- --------
OTHER PROPERTY AND INVESTMENTS 119 119
-------- --------
CURRENT ASSETS:
Cash and Cash Equivalents - 983
Accounts Receivable:
Affiliated Companies 28,800 22,344
Miscellaneous 147 147
Fuel - at average cost 19,157 15,243
Materials and Supplies - at average cost 4,437 4,480
Prepayments 86 244
-------- --------
TOTAL CURRENT ASSETS 52,627 43,441
-------- --------
REGULATORY ASSETS 5,089 5,207
-------- --------
DEFERRED CHARGES 2,973 1,471
-------- --------
TOTAL ASSETS $366,762 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 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 15,272 13,761
-------- --------
Total Common Shareholder's Equity 39,706 38,195
Long-term Debt 44,798 44,793
-------- --------
TOTAL CAPITALIZATION 84,504 82,988
-------- --------
OTHER NONCURRENT LIABILITIES 421 76
-------- --------
CURRENT LIABILITIES:
Advances from Affiliates 9,775 32,049
Accounts Payable:
General 8,770 7,582
Affiliated Companies 29,867 1,654
Taxes Accrued 8,592 4,777
Rent Accrued - Rockport Plant Unit 2 4,963 4,963
Other 3,641 3,481
-------- --------
TOTAL CURRENT LIABILITIES 65,608 54,506
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
PLANT UNIT 2 113,832 116,617
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credit 54,635 56,304
Amounts Due to Customers for Income Taxes 21,393 22,725
-------- --------
TOTAL REGULATORY LIABILITIES 76,028 79,029
-------- --------
DEFERRED INCOME TAXES 26,369 27,975
-------- --------
DEFERRED CREDITS - 150
-------- --------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $366,762 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2002 2001
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 3,611 $ 4,043
Adjustment for Noncash Items:
Depreciation 11,275 11,188
Deferred Income Taxes (2,938) (2,935)
Deferred Investment Tax Credits (1,669) (1,673)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (2,785) (2,785)
Deferred Property Taxes (1,786) (1,829)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (6,456) 5,713
Fuel, Materials and Supplies (3,871) (7,644)
Accounts Payable 29,401 6,852
Taxes Accrued 3,815 5,833
Change in Other Assets 43 (5)
Change in Other Liabilities 355 (2,366)
-------- --------
Net Cash Flow From Operating Activities 28,995 14,392
-------- --------
INVESTING ACTIVITIES - Construction Expenditures (5,604) (1,537)
-------- --------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) (22,274) (12,903)
Dividends Paid (2,100) (1,918)
-------- --------
Net Cash Flows Used For Financing Activities (24,374) (14,821)
-------- --------
Net Increase in Cash and Cash Equivalents (983) (1,966)
Cash and Cash Equivalents at Beginning of Period 983 2,757
-------- --------
Cash and Cash Equivalents at End of Period $ - $ 791
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,132,000 and $1,143,000
and for income taxes was $1,217,000 and $1,350,000 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
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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.
Results of Operations
Net income increased $10.2 million or 28% for the quarter due to
decreased interest charges and lower general operating expenses. Net income
increased $3.7 million or 4% for the year-to-date period due to decreases in
interest charges offset in part by lower wholesale energy prices that reduced
margins.
The following analyzes the changes in operating revenues:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
and Trading Purchases $(543) (33) $(1,059) (31)
Energy Delivery* (8) (6) (6) (2)
Sales to AEP Affiliates 5 12 - -
----- -------
Total $(546) (30) $(1,065) (28)
===== =======
*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 sales by the AEP
Power Pool due to lower wholesale energy prices. In 2002 the wholesale energy
sector has been under pressure from lower commodity prices in contrast to last
year when we had strong performance from the wholesale business due to favorable
market conditions. 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.
Energy delivery revenues decreased due to the continuing economic
recession in 2002.
The changes in the components of operating expenses were:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $ 22 26 $ 34 19
Electricity Marketing
and Trading Purchases (543) (38) (1,016) (35)
Purchases from AEP Affiliates (27) (32) (72) (38)
Other Operation (4) (6) (2) (2)
Maintenance (6) (18) (13) (20)
Depreciation and Amortization 3 6 6 7
Taxes Other Than Income Taxes - - (1) (1)
Income Taxes 3 15 - -
----- --------
Total $(552) (31) $(1,064) (29)
===== =======
Fuel expense increased due to an increase in electric generation as
certain plants that had undergone boiler plant maintenance in 2001 were
available for service in 2002.
The decline in electricity marketing and trading purchases was mainly
due to reduced prices caused by market conditions affecting the electricity
trading industry.
Purchases from AEP affiliates decreased due to the increase in internal
generation as a result of certain plants being available for service in 2002
that had undergone boiler plant maintenance in 2001.
The decrease in other operations expense in the quarter is mainly due to
a decrease in transmission equalization charges caused by a reduction in APCo's
MLR.
The decrease in maintenance expense is primarily due to the effect of
boiler plant maintenance performed on certain plants in 2001.
Depreciation and amortization expense increased predominantly 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 4 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 increase in income taxes from operations for the quarter was due to
an increase 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
market conditions affecting the electricity trading industry in the second
quarter and by decreased electricity demand in the first quarter resulting
from mild weather and the slow economic recovery.
The decrease in interest charges for the quarter was due to increased
allowances for borrowed funds as a result of increased construction expenditures
and lower AEP money pool interest rates and balances. Interest charges decreased
for the year-to-date period primarily due to increased allowances for borrowed
funds as a result of increased construction expenditures, the retirement of
first mortgage bonds on March 1, 2001 and lower AEP money pool interest rates.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $1,113,871 $1,656,905 $2,371,226 $3,430,799
Energy Delivery 139,475 147,924 294,470 300,021
Sales to AEP Affiliates 49,934 44,475 92,740 92,611
---------- ---------- ---------- ----------
TOTAL OPERATING REVENUES 1,303,280 1,849,304 2,758,436 3,823,431
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 107,160 85,049 214,650 180,525
Purchased Power:
Electricity Marketing and Trading 885,469 1,427,844 1,891,068 2,907,372
AEP Affiliates 58,717 85,987 119,497 191,661
Other Operation 64,158 67,948 131,585 133,837
Maintenance 27,638 33,842 53,489 66,851
Depreciation and Amortization 46,909 44,056 93,681 87,773
Taxes Other Than Income Taxes 25,050 25,257 50,045 50,685
Income Taxes 22,955 19,959 57,643 57,213
---------- ---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,238,056 1,789,942 2,611,658 3,675,917
---------- ---------- ---------- ----------
OPERATING INCOME 65,224 59,362 146,778 147,514
NONOPERATING INCOME 422,518 649,030 822,690 1,114,435
NONOPERATING EXPENSES 408,245 637,831 806,978 1,096,036
NONOPERATING INCOME TAX EXPENSE 4,820 3,427 5,084 5,576
INTEREST CHARGES 28,069 30,715 55,457 62,131
---------- ---------- ---------- ----------
NET INCOME 46,608 36,419 101,949 98,206
PREFERRED STOCK DIVIDEND
REQUIREMENTS 503 503 1,006 1,006
---------- ---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 46,105 $ 35,916 $ 100,943 $ 97,200
========== ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $46,608 $36,419 $101,949 $98,206
OTHER COMPREHENSIVE INCOME (LOSS):
Cashflow Power Hedges 2,217 - 2,217 -
Cashflow Interest Rate Hedge (2,128) - (2,128) -
Foreign Currency Exchange Rate
Hedge - (212) 143 (629)
------- ------- -------- -------
COMPREHENSIVE INCOME $46,697 $36,207 $102,181 $97,577
======= ======= ======== =======
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 June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $174,651 $149,469 $150,797 $120,584
NET INCOME 46,608 36,419 101,949 98,206
-------- -------- -------- --------
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 30,984 32,398 61,968 64,797
Preferred Stock 360 360 721 721
Capital Stock Expense 142 143 284 285
-------- -------- -------- --------
BALANCE AT END OF PERIOD $189,773 $152,987 $189,773 $152,987
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,107,053 $2,093,532
Transmission 1,215,707 1,222,226
Distribution 1,910,496 1,887,020
General 258,731 257,957
Construction Work in Progress 288,146 203,922
---------- ----------
Total Electric Utility Plant 5,780,133 5,664,657
Accumulated Depreciation and Amortization 2,370,959 2,296,481
---------- ----------
NET ELECTRIC UTILITY PLANT 3,409,174 3,368,176
---------- ----------
OTHER PROPERTY AND INVESTMENTS 51,886 53,736
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 490,983 316,249
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 1,304 13,663
Advances to Affiliates 95,498 -
Accounts Receivable:
Customers 130,219 113,371
Affiliated Companies 204,490 63,368
Miscellaneous 22,598 11,847
Allowance for Uncollectible Accounts (2,096) (1,877)
Fuel - at average cost 38,902 56,699
Materials and Supplies - at average cost 57,262 59,849
Accrued Utility Revenues 22,919 30,907
Energy Trading Contracts 794,212 566,284
Prepayments and Other 29,359 16,018
---------- ----------
TOTAL CURRENT ASSETS 1,394,667 930,129
---------- ----------
REGULATORY ASSETS 387,785 397,383
---------- ----------
DEFERRED CHARGES 42,867 42,265
---------- ----------
TOTAL ASSETS $5,777,362 $5,107,938
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 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 716,071 715,786
Accumulated Other Comprehensive Income (Loss) (108) (340)
Retained Earnings 189,773 150,797
---------- ----------
Total Common Shareowner's Equity 1,166,194 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 1,690,024 1,476,552
---------- ----------
TOTAL CAPITALIZATION 2,884,868 2,631,903
---------- ----------
OTHER NONCURRENT LIABILITIES 86,148 84,104
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 315,007 80,007
Advances from Affiliates - 291,817
Accounts Payable - General 126,032 131,387
Accounts Payable - Affiliated Companies 142,918 84,518
Taxes Accrued 90,827 55,583
Customer Deposits 20,113 13,177
Interest Accrued 28,180 21,770
Energy Trading Contracts 760,856 549,703
Other 65,784 75,299
---------- ----------
TOTAL CURRENT LIABILITIES 1,549,717 1,303,261
---------- ----------
DEFERRED INCOME TAXES 696,835 703,575
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 36,132 38,328
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 432,097 257,129
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 91,565 89,638
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,777,362 $5,107,938
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2002 2001
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 101,949 $ 98,206
Adjustments for Noncash Items:
Depreciation and Amortization 93,737 87,829
Deferred Income Taxes (7,055) 31,726
Deferred Investment Tax Credits (2,196) (2,212)
Mark-to-Market Energy Trading Contracts (12,797) (97,010)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (168,502) 69,776
Fuel, Materials and Supplies 20,384 (4,859)
Accrued Utility Revenues 7,988 48,007
Accounts Payable 53,045 (3,747)
Taxes Accrued 35,244 10,438
Interest Accrued 6,410 5,924
Change in Other Assets (13,851) 22,683
Change in Other Liabilities 7,449 (39,002)
--------- ---------
Net Cash Flows From Operating Activities 121,805 227,759
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (128,853) (107,876)
Proceeds from Sale of Property 583 1,182
--------- ---------
Net Cash Flows Used For Investing Activities (128,270) (106,694)
--------- ---------
FINANCING ACTIVITIES:
Change in Short-term Debt (net) - (191,495)
Change in Advances to Affiliates (net) (387,315) 310,277
Issuance of Long-term Debt 444,110 -
Retirement of Long-term Debt - (175,000)
Dividends Paid on Common Stock (61,968) (64,797)
Dividends Paid on Cumulative Preferred Stock (721) (721)
--------- ---------
Net Cash Flows Used For Financing Activities (5,894) (121,736)
--------- ---------
Net Decrease in Cash and Cash Equivalents (12,359) (671)
Cash and Cash Equivalents at Beginning of Period 13,663 5,847
-------- ---------
Cash and Cash Equivalents at End of Period $ 1,304 $ 5,176
======== =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $47,676,000 and
$54,957,000 and for income taxes was $36,585,000 and $17,064,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $1,684,000 in
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
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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, 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. 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 determine the fair value of 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 the "Quantitative and
Qualitative Disclosure About Market Risk" section of Part I, Item 2 for a
discussion of the policies and procedures used to manage exposure to risk from
trading activities.
Results of Operations
Second quarter net income decreased $19 million or 36%, while the
year-to-date net income decreased $30 million or 34% primarily due to a slow
economic recovery, a significant decline in wholesale prices and the replacement
of sales to ultimate retail customers with sales to the REP's in the ERCOT area
beginning on January 1, 2002. Operating revenues decreased $171 million for the
quarter and $371 million year-to-date as shown below:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
and Trading* $(390) (83) $(751) (80)
Energy Delivery* 8 5 10 4
Sales to AEP Affiliates 211 N.M. 370 N.M.
----- -----
Total $(171) (26) $(371) (30)
===== =====
*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 as a result of the
elimination of retail sales in the ERCOT area as of January 1, 2002 and a
decrease in energy trading. In 2002 the wholesale energy sector has been under
pressure from lower commodity prices in contrast to last year when we had
strong performance from the wholesale business due to favorable market
conditions. Revenues from sales to AEP affiliates rose substantially due to
the supplying of electricity to the newly formed affiliated REP's.Although CPL
sold electricity to the affiliated REP instead of directly to retail customers
in the ERCOT area, total revenues received were lower because of the lower
wholesale prices.
Operating expenses declined 27% for the quarter and 31% year-to-date.
The changes in the components of operating expenses were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $ (57) (39) $(155) (52)
Electricity Marketing
and Trading Purchases (84) (40) (157) (38)
Purchases from AEP Affiliates (1) (11) (6) (24)
Other Operation (4) (6) (13) (9)
Maintenance (3) (18) (10) (27)
Depreciation and Amortization 7 14 7 7
Taxes Other Than Income Taxes 6 35 15 40
Income Taxes (17) (50) (25) (48)
----- -----
Total $(153) (27) $(344) (31)
===== =====
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 and lower wholesale prices due to the slow economic
recovery.
The decrease in maintenance and other operation expenses resulted from
the effects of a STP nuclear plant 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 June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $ 77,617 $ 468,428 $ 189,052 $ 940,722
Energy Delivery 176,828 168,433 288,955 278,763
Sales to AEP Affiliates 223,092 11,638 402,753 32,426
-------- ---------- --------- ----------
TOTAL OPERATING REVENUES 477,537 648,499 880,760 1,251,911
-------- ---------- --------- ----------
OPERATING EXPENSES:
Fuel 89,956 147,179 144,284 299,032
Purchased Power:
Electricity Marketing and Trading 123,118 206,733 251,443 408,529
Affiliates 12,564 14,039 20,491 26,809
Other Operation 71,975 76,189 137,961 151,260
Maintenance 14,782 17,995 25,741 35,282
Depreciation and Amortization 60,923 53,587 102,770 95,978
Taxes Other Than Income Taxes 23,474 17,330 51,396 36,818
Income Taxes 16,426 33,096 26,910 51,700
-------- ---------- --------- ----------
TOTAL OPERATING EXPENSES 413,218 566,148 760,996 1,105,408
-------- ---------- --------- ----------
OPERATING INCOME 64,319 82,351 119,764 146,503
NONOPERATING INCOME (LOSS) 4,472 (697) 14,003 2,502
NONOPERATING EXPENSES 3,478 810 12,865 1,647
NONOPERATING INCOME TAX EXPENSE (CREDIT) (648) 34 (515) 757
INTEREST CHARGES 32,426 28,292 63,437 59,052
-------- ---------- --------- ----------
NET INCOME 33,535 52,518 57,980 87,549
PREFERRED STOCK DIVIDEND REQUIREMENTS 61 61 121 121
-------- ---------- --------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 33,474 $ 52.457 $ 57,859 $ 87,428
======== ========== ========= ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $33,535 $52,518 $57,980 $87,549
OTHER COMPREHENSIVE INCOME
Cash Flow Power Hedge 263 - 263 -
------- ------- ------- -------
COMPREHENSIVE INCOME $33,798 $52,518 $58,243 $87,549
======= ======= ======= =======
The common stock of CP&L is wholly owned by AEP. See Notes to Financial
Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $812,080 $790,176 $826,197 $792,219
NET INCOME 33,535 52,518 57,980 87,549
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 38,502 37,014 77,004 74,028
Preferred Stock 61 61 121 121
-------- -------- -------- --------
BALANCE AT END OF PERIOD $807,052 $805,619 $807,052 $805,619
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $3,175,010 $3,169,421
Transmission 698,909 663,655
Distribution 1,301,563 1,279,037
General 243,438 241,137
Construction Work in Progress 158,562 169,075
Nuclear Fuel 251,157 247,382
---------- ----------
Total Electric Utility Plant 5,828,639 5,769,707
Accumulated Depreciation and Amortization 2,518,016 2,446,027
---------- ----------
NET ELECTRIC UTILITY PLANT 3,310,623 3,323,680
---------- ----------
OTHER PROPERTY AND INVESTMENTS 50,005 47,950
---------- ----------
SECURITIZED TRANSITION ASSET 750,939 -
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 31,136 72,502
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 28,385 10,909
Accounts Receivable:
General 87,683 38,459
Affiliated Companies 228,135 6,249
Allowance for Uncollectible Accounts (505) (186)
Fuel Inventory - at LIFO cost 42,997 38,690
Materials and Supplies - at average cost 52,239 55,475
Energy Trading Contracts 64,633 212,979
Prepayments and Other Current Assets 5,432 2,742
---------- ----------
TOTAL CURRENT ASSETS 508,999 365,317
---------- ----------
REGULATORY ASSETS 227,100 226,806
---------- ----------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 171,066 959,294
---------- ----------
NUCLEAR DECOMMISSIONING TRUST FUND 97,429 98,600
---------- ----------
DEFERRED CHARGES 89,202 21,837
---------- ----------
TOTAL ASSETS $5,236,499 $5,115,986
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 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 June 30, 2002
6,755,535 Shares at December 31, 2001 $ 55,292 $ 168,888
Paid-in Capital 132,592 405,000
Accumulated Other Comprehensive Income 263 -
Retained Earnings 807,052 826,197
---------- ----------
Total Common Shareowner's Equity 995,199 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 1,704,374 988,768
---------- ----------
TOTAL CAPITALIZATION 2,841,790 2,531,070
---------- ----------
CURRENT LIABILITIES:
Short-term Debt Affiliate 200,000 -
Long-term Debt Due Within One Year 196,017 265,000
Advances from Affiliates 102,285 354,277
Accounts Payable - General 66,204 65,307
Accounts Payable - Affiliated Companies 155,097 49,301
Customer Deposits 555 26,744
Over Recovered Fuel 61,867 57,762
Taxes Accrued 109,163 83,512
Interest Accrued 25,606 18,524
Energy Trading Contracts 67,321 219,486
Other 23,009 22,768
---------- ----------
TOTAL CURRENT LIABILITIES 1,007,124 1,162,681
---------- ----------
DEFERRED INCOME TAXES 1,147,562 1,163,795
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 120,289 122,892
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 28,118 62,138
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 91,616 73,410
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,236,499 $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)
Six Months Ended June 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 57,980 $ 87,549
Adjustments for Noncash Items:
Depreciation and Amortization 102,770 95,978
Deferred Income Taxes (18,103) (17,699)
Deferred Investment Tax Credits (2,603) (2,604)
Deferred Property Taxes (19,120) (21,563)
Mark-to-Market Energy Trading Contracts 3,932 (8,338)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (270,791) 47,588
Fuel, Materials and Supplies (1,071) (17,688)
Fuel Recovery 4,105 33,954
Accounts Payable 106,693 (27,530)
Taxes Accrued 25,651 73,457
Change in Other Assets (38,746) (13,442)
Change in Other Liabilities (566) 4,152
--------- ---------
Net Cash Flows From (Used For) Operating Activities (49,869) 233,814
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (64,147) (109,638)
Other - (354)
--------- ---------
Net Cash Flows Used For Investing Activities (64,147) (109,992)
--------- ----------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 796,613 -
Retirement of Long-term Debt (150,000) (11,971)
Change in Short-term Debt Affiliated (net) 200,000 -
Retirement of Common Stock (386,004) -
Change in Advances from Affiliates (net) (251,992) (46,200)
Dividends Paid on Common Stock (77,004) (74,028)
Dividends Paid on Cumulative Preferred Stock (121) (121)
--------- ---------
Net Cash Flows From (Used For) Financing Activities 131,492 (132,320)
--------- ---------
Net Decrease in Cash and Cash Equivalents 17,476 (8,498)
Cash and Cash Equivalents at Beginning of Period 10,909 14,253
--------- ---------
Cash and Cash Equivalents at End of Period $ 28,385 $ 5,755
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $40,588,000 and
$46,083,000 and for income taxes was $44,322,000 and $11,307,000 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
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 increased $30.7 million or 146% in the second quarter of 2002
and $26.9 million or 46% in the year-to-date period due to an extraordinary loss
recorded in the prior period second quarter to recognize a stranded asset
resulting from deregulation.
A decline in revenues is mainly due to a decrease in wholesale sales
revenues due to lower wholesale energy prices. In 2002 the wholesale energy
sector has been under pressure from lower commodity prices in contrast to last
year when we had strong performance from the wholesale business due to favorable
market conditions. The following analyzes the changes in operating revenues:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
And Trading* $(197.1) (20) $(365.8) (18)
Energy Delivery* 2.8 2 6.3 3
Sales to AEP Affiliates (1.7) (9) (12.7) (34)
------- -------
Total $(196.0) (18) $(372.2) (17)
======= =======
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The decrease in electric marketing and trading revenues was largely
driven by the decline in sales by the AEP Power Pool due to lower wholesale
energy prices that decreased margins.
Operating expenses declined 18% in the second quarter of 2002 and 17% in
the year-to-date period of 2002. The changes in the components of operating
expenses were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $ 0.7 2 $ (0.7) (1)
Electricity Marketing
and Trading Purchases (204.7) (26) (366.4) (23)
Purchases from AEP
Affiliates 10.1 15 9.4 7
Other Operation 7.8 14 7.4 7
Maintenance (4.7) (24) (9.3) (24)
Depreciation and
Amortization 1.0 3 2.3 4
Taxes other Than Income
Taxes (2.7) (9) (3.2) (5)
Income Taxes 1.4 7 (0.5) (1)
------- -------
Total $(191.1) (18) $(361.0) (17)
======= =======
Electricity marketing and trading purchases also declined due to lower
wholesale energy costs driven by market conditions.
Other operation expense increased in both periods primarily due to
post retirement benefits expense and property insurance.
Maintenance expenses decreased in the second quarter and year-to-date
of 2002 due to boiler overhaul work that was performed during 2001. Expenses
for maintaining distribution overhead lines and underground lines were also
lower in both periods of 2002.
The increase in income taxes for the second quarter is predominately due
to an increase in pre-tax income. The decrease in income taxes for the
year-to-date period 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 offset in part by a decrease in deferred state taxes.
The decrease in nonoperating income which was offset by a larger
decrease 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.
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 June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $772,779 $ 969,836 $1,611,868 $1,977,667
Energy Delivery 123,062 120,314 225,610 219,310
Sales to AEP Affiliates 17,275 18,945 24,953 37,691
-------- ---------- ---------- ----------
TOTAL OPERATING REVENUES 913,116 1,109,095 1,862,431 2,234,668
-------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 43,064 42,368 88,714 89,398
Purchased Power:
Electricity Marketing and Trading 572,644 777,356 1,210,565 1,576,995
AEP Affiliates 78,622 68,504 150,204 140,776
Other Operation 62,273 54,510 116,431 109,058
Maintenance 15,050 19,729 29,190 38,509
Depreciation and Amortization 32,402 31,379 65,138 62,861
Taxes Other Than Income Taxes 29,330 32,079 59,606 62,766
Income Taxes 21,691 20,276 38,995 39,479
-------- ---------- ---------- ----------
TOTAL OPERATING EXPENSES 855,076 1,046,201 1,758,843 2,119,842
-------- ---------- ---------- ----------
OPERATING INCOME 58,040 62,894 103,588 114,826
NONOPERATING INCOME 275,637 352,505 533,215 605,351
NONOPERATING EXPENSES 265,114 348,255 519,242 596,047
NONOPERATING INCOME TAX EXPENSE 3,450 1,238 4,797 2,820
INTEREST CHARGES 13,392 18,488 27,185 36,221
-------- ---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 51,721 47,418 85,579 85,089
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION (INCLUSIVE OF TAX BENEFIT
OF $8,353,000) - (26,407) - (26,407)
-------- ---------- ---------- ----------
NET INCOME 51,721 21,011 85,579 58,682
PREFERRED STOCK DIVIDEND REQUIREMENTS 203 301 384 603
-------- ---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 51,518 $ 20,710 $ 85,195 $ 58,079
======== ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $51,721 $21,011 $85,579 $58,682
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Power Hedge 1,449 - 1,449 -
------- ------- ------- -------
COMPREHENSIVE INCOME $53,170 $21,011 $87,028 $58,682
======= ======= ======= =======
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 STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $187,766 $115,486 $176,103 $ 99,069
NET INCOME 51,721 21,011 85,579 58,682
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 21,768 20,738 43,534 41,476
Preferred Stock 175 263 350 525
Capital Stock Expense 254 253 508 507
-------- -------- -------- --------
BALANCE AT END OF PERIOD $217,290 $115,243 $217,290 $115,243
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,579,404 $1,574,506
Transmission 409,373 401,405
Distribution 1,183,240 1,159,105
General 149,750 146,732
Construction Work in Progress 80,695 72,572
---------- ----------
Total Electric Utility Plant 3,402,462 3,354,320
Accumulated Depreciation and Amortization 1,424,191 1,377,032
---------- ----------
NET ELECTRIC UTILITY PLANT 1,978,271 1,977,288
---------- ----------
OTHER PROPERTY AND INVESTMENTS 39,319 40,369
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 320,819 193,915
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 3,414 12,358
Advances to Affiliates 20,709 -
Accounts Receivable:
Customers 53,347 41,770
Affiliated Companies 154,468 63,470
Miscellaneous 17,006 16,968
Allowance for Uncollectible Accounts (751) (745)
Fuel - at average cost 21,864 20,019
Materials and Supplies - at average cost 39,716 38,984
Accrued Utility Revenues 17,376 7,087
Energy Trading Contracts 518,838 347,198
Prepayments and Other Current Assets 37,919 28,733
---------- ----------
TOTAL CURRENT ASSETS 883,906 575,842
---------- ----------
REGULATORY ASSETS 257,378 262,267
---------- ----------
DEFERRED CHARGES 34,658 56,187
---------- ----------
TOTAL ASSETS $3,514,351 $3,105,868
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 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 574,877 574,369
Accumulated Other Comprehensive Income 1,449 -
Retained Earnings 217,290 176,103
---------- ----------
Total Common Shareowner's Equity 834,642 791,498
Cumulative Preferred Stock - Subject to
Mandatory Redemption - 10,000
Long-term Debt 445,691 571,348
---------- ----------
TOTAL CAPITALIZATION 1,280,333 1,372,846
---------- ----------
OTHER NONCURRENT LIABILITIES 37,350 36,715
---------- ----------
CURRENT LIABILITIES:
Preferred Stock Due Within One Year 10,000 -
Long-term Debt Due Within One Year 346,343 220,500
Short-term Debt Affiliated 250,000 -
Advances from Affiliates - 181,384
Accounts Payable - General 64,131 62,393
Accounts Payable - Affiliated Companies 130,130 83,697
Taxes Accrued 83,181 116,364
Interest Accrued 10,996 10,907
Energy Trading Contracts 495,172 334,958
Other 32,889 34,600
---------- ----------
TOTAL CURRENT LIABILITIES 1,422,842 1,044,803
---------- ----------
DEFERRED INCOME TAXES 439,988 443,722
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 35,619 37,176
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 282,341 157,706
---------- ----------
DEFERRED CREDITS 15,878 12,900
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $3,514,351 $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)
Six Months Ended June 30,
(in thousands)
2002 2001
---- ----
OPERATING ACTIVITIES:
Net Income $ 85,579 $ 58,682
Adjustments for Noncash Items:
Depreciation and Amortization 65,192 63,686
Deferred Federal Income Taxes (5,432) 18,384
Deferred Investment Tax Credits (1,557) (1,671)
Deferred Property Tax 23,971 35,416
Mark-to-Market Energy Trading Contracts (11,260) (52,316)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (102,607) (37,869)
Fuel, Materials and Supplies (2,577) (6,758)
Accrued Utility Revenues (10,289) 9,638
Prepayments and Other Current Assets (9,186) 19,077
Accounts Payable 48,171 28,155
Taxes Accrued (33,183) (45,627)
Other Assets (7,865) 10,516
Other Liabilities 3,529 (19,204)
--------- --------
Net Cash Flows From Operating Activities 42,486 80,109
--------- --------
INVESTING ACTIVITIES:
Construction Expenditures (55,842) (67,532)
Proceeds from Sale of Property 389 1,284
--------- --------
Net Cash Flows Used For Investing Activities (55,453) (66,248)
--------- --------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) (202,093) 26,570
Change in Short-term Debt Affiliated (net) 250,000 -
Dividends Paid on Common Stock (43,534) (41,476)
Dividends Paid on Cumulative Preferred Stock (350) (525)
--------- --------
Net Cash Flows From (Used For) Financing Activities 4,023 (15,431)
--------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (8,944) (1,570)
Cash and Cash Equivalents at Beginning of Period 12,358 11,600
--------- --------
Cash and Cash Equivalents at End of Period $ 3,414 $ 10,030
========= ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $26,262,000 and
$32,812,000 and for income taxes was $32,254,000 and $17,579,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $734,000 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
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 $19.9 million or 73% in the second quarter and
$41.2 million or 69% in the year-to-date period due primarily to a reduction in
generation as a result of a refueling outage at both units of I&M's Cook Plant,
reduced generation at Rockport Plant due to maintenance outages and lower
margins on electricity sales.
Operating revenues decreased 22% in the second quarter and 21% for the
year-to-date period 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)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
and Trading* $(255.5) (23) $(481.1) (21)
Energy Delivery* (0.3) N.M. (3.7) (2)
Sales to AEP Affiliates (19.0) (30) (42.8) (32)
------- -------
Total $(274.8) (22) $(527.6) (21)
======= =======
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
N.M. = Not Meaningful
The decrease in electricity marketing and trading revenues was due to a
decline in sales by the AEP Power Pool due to lower wholesale energy prices.
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 in each of the first two quarters of 2002 and both units
of Rockport Plant underwent scheduled planned boiler maintenance in the first
quarter of 2002. 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 in 2002. The changes in the components of
operating expenses were:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $ (7.3) (12) $ (17.1) (14)
Electricity Marketing
and Trading Purchases (260.1) (30) (476.3) (27)
Purchases from AEP
Affiliates 7.3 13 (2.7) (2)
Other Operation 11.0 10 25.4 12
Maintenance 8.0 26 10.9 18
Depreciation and
Amortization 1.0 3 2.2 3
Taxes other Than Income
Taxes 0.5 3 0.5 1
Income Taxes (7.8) (50) (20.6) (60)
------- -------
Total $(247.4) (20) $(477.8) (19)
======= =======
Fuel expense decreased primarily due to the decline in generation
reflecting the plant outages as both units of our nuclear plant were refueled in
2002.
The decrease in electricity marketing and trading purchases resulted
mainly from the decrease in energy prices.
Purchases from AEP affiliates increased in the second quarter due to
the timing of the Rockport Plant outages in first quarter of 2002 and in second
quarter of 2001. I&M is required to purchase AEGCo's Rockport Plant
generation under their unit power agreement.
Other operation and maintenance expenses increased due to costs related
to the nuclear plant refueling outages.
The decrease in income tax expense attributable to operations is due
primarily to a decline in pre-tax operating income.
Nonoperating income and nonoperating expenses decreased 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.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $860,979 $1,116,459 $1,777,992 $2,259,076
Energy Delivery 78,657 78,970 153,194 156,907
Sales to AEP Affiliates 45,401 64,445 92,610 135,429
-------- ---------- ---------- ----------
TOTAL OPERATING REVENUES 985,037 1,259,874 2,023,796 2,551,412
-------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 53,163 60,491 107,319 124,464
Purchased Power:
Electricity Marketing and Trading 620,545 880,649 1,312,351 1,788,688
AEP Affiliates 63,110 55,805 116,617 119,353
Other Operation 121,180 110,197 232,946 207,560
Maintenance 39,580 31,506 70,623 59,681
Depreciation and Amortization 41,870 40,840 83,736 81,563
Taxes Other Than Income Taxes 17,855 17,336 36,096 35,574
Income Taxes 7,869 15,710 13,880 34,491
-------- ---------- ---------- ----------
TOTAL OPERATING EXPENSES 965,172 1,212,534 1,973,568 2,451,374
-------- ---------- ---------- ----------
OPERATING INCOME 19,865 47,340 50,228 100,038
NONOPERATING INCOME 315,454 415,752 610,639 718,026
NONOPERATING EXPENSES 303,005 409,323 594,496 705,037
NONOPERATING INCOME TAX EXPENSE 1,313 2,018 888 4,133
INTEREST CHARGES 23,507 24,377 46,931 49,157
-------- ---------- ---------- ----------
NET INCOME 7,494 27,374 18,552 59,737
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,153 1,156 2,308 2,311
-------- ---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 6,341 $ 26,218 $ 16,244 $ 57,426
======== ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $ 7,494 $27,374 $18,552 $59,737
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge 1,228 (903) 2,487 (2,822)
Power Trading Hedge 1,567 - 1,567 -
------- ------- ------- -------
COMPREHENSIVE INCOME $10,289 $26,471 $22,606 $56,915
======= ======= ======= =======
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 June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $84,508 $34,651 $74,605 $ 3,443
NET INCOME 7,494 27,374 18,552 59,737
DEDUCTIONS:
Cash Dividends Declared -
Cumulative Preferred Stock 1,121 1,122 2,243 2,244
Capital Stock Expense 34 34 67 67
------- ------- ------- -------
BALANCE AT END OF PERIOD $90,847 $60,869 $90,847 $60,869
======= ======= ======= =======
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,765,097 $2,758,160
Transmission 958,863 957,336
Distribution 907,104 900,921
General (including nuclear fuel) 238,213 233,005
Construction Work in Progress 114,117 74,299
---------- ----------
Total Electric Utility Plant 4,983,394 4,923,721
Accumulated Depreciation and Amortization 2,505,922 2,436,972
---------- ----------
NET ELECTRIC UTILITY PLANT 2,477,472 2,486,749
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS 851,070 834,109
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 356,052 215,544
---------- ----------
OTHER PROPERTY AND INVESTMENTS 121,961 127,977
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 13,708 16,804
Advances to Affiliates - 46,309
Accounts Receivable:
Customers 76,763 60,864
Affiliated Companies 189,093 31,908
Miscellaneous 41,366 25,398
Allowance for Uncollectible Accounts (715) (741)
Fuel - at average cost 29,340 28,989
Materials and Supplies - at average cost 90,900 91,440
Energy Trading Contracts 587,571 399,195
Accrued Utility Revenues 2,920 2,072
Prepayments 11,027 6,497
---------- ----------
TOTAL CURRENT ASSETS 1,041,973 708,735
---------- ----------
REGULATORY ASSETS 412,308 408,927
---------- ----------
DEFERRED CHARGES 36,183 34,967
---------- ----------
TOTAL ASSETS $5,297,019 $4,817,008
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 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 733,491 733,216
Accumulated Other Comprehensive Income (Loss) 219 (3,835)
Retained Earnings 90,847 74,605
---------- ----------
Total Common Shareowner's Equity 881,141 860,570
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,103 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,364,500 1,312,082
---------- ----------
TOTAL CAPITALIZATION 2,318,689 2,246,333
---------- ----------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 610,986 600,244
Other 85,716 87,025
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES 696,702 687,269
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 290,000 340,000
Advances from Affiliates 11,806 -
Accounts Payable:
General 118,187 90,817
Affiliated Companies 150,769 43,956
Taxes Accrued 68,048 69,761
Interest Accrued 23,398 20,691
Obligations Under Capital Leases 9,025 10,840
Energy Trading Contracts 564,572 383,714
Other 79,169 72,435
---------- ----------
TOTAL CURRENT LIABILITIES 1,314,974 1,032,214
---------- ----------
DEFERRED INCOME TAXES 384,370 400,531
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 101,760 105,449
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK
- ROCKPORT PLANT UNIT 2 75,739 77,592
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 318,158 175,581
---------- ----------
DEFERRED CREDITS 86,627 92,039
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,297,019 $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)
Six Months Ended June 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 18,552 $ 59,737
Adjustments for Noncash Items:
Depreciation and Amortization 83,779 83,090
Deferral of Incremental Nuclear
Refueling Outage Expenses (net) (45,701) (771)
Unrecovered Fuel and Purchased Power Costs 18,751 18,751
Amortization of Nuclear Outage Costs 20,000 20,000
Deferred Federal Income Taxes (7,723) (4,256)
Deferred Investment Tax Credits (3,689) (3,736)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (189,078) 10,372
Fuel, Materials and Supplies 189 (13,858)
Accrued Utility Revenues (848) -
Accounts Payable 134,183 (41,383)
Taxes Accrued (1,713) 31,255
Mark-to-Market Energy Trading Contracts 2,377 (84,756)
Regulatory Liability - Trading Gains 838 34,080
Regulatory Assets - Trading Losses (8,166) 4,079
Change in Other Assets (24,349) 18,409
Change in Other Liabilities 11,802 (1,448)
--------- ---------
Net Cash Flows From Operating Activities 9,204 129,565
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (67,396) (41,321)
Buyout of Nuclear Fuel Leases - (92,616)
Other - 324
--------- ---------
Net Cash Flows Used For Investing Activities (67,396) (133,613)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 49,648 -
Retirement of Cumulative Preferred Stock (424) -
Retirement of Long-term Debt (50,000) (44,922)
Change in Advances from Affiliates (net) 58,115 48,448
Dividends Paid on Cumulative Preferred Stock (2,243) (2,244)
--------- ---------
Net Cash Flows From Financing Activities 55,096 1,282
--------- ---------
Net Decrease in Cash and Cash Equivalents (3,096) (2,766)
Cash and Cash Equivalents at Beginning of Period 16,804 14,835
--------- ---------
Cash and Cash Equivalents at End of Period $ 13,708 $ 12,069
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $42,695,000 and
$46,243,000 and for income taxes was $18,711,000 and $11,073,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $1,020,000 in
2001.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 the "Quantitative and
Qualitative Disclosures About Market Risk" section of Part I, Item 2 for a
discussion of the policies and procedures used to manage exposure to risk from
trading activities.
Results of Operations
Revenues decreased for both the quarter and year-to-date by 28% and 26%,
respectively. These declines were offset by improvements in both operating and
nonoperating margins resulting in increases in net income of 91% and 58% or $2.5
million for the quarter and $5.7 million year-to-date.
The following analyzes the changes in operating revenues:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
and Trading* $(120) (30) $(222) (27)
Energy Delivery* 1 2 (1) (1)
Sales to AEP Affiliates (3) (26) (7) (31)
----- -----
Total $(122) (28) $(230) (26)
===== =====
*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 in both the first and second quarter. In 2002 the wholesale
energy sector has been under pressure from lower commodity prices in contrast to
last year when we had strong performance from the wholesale business due to
favorable market conditions.
Significant changes in the components of operating expenses were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $ - - $ 4 11
Electricity Marketing
and Trading Purchases (125) (36) (231) (33)
Purchases from AEP Affiliates - - (7) (10)
Other Operation (2) (11) (4) (13)
Maintenance 3 56 2 19
Taxes Other Than Income Taxes 1 25 1 14
Income Taxes (1) (25) 1 12
Year-to-date fuel expense increased as a result of fewer credits from
profits on trading power and increases in the cost of coal. Under the Kentucky
commission's fuel clause mechanism, a portion of the profits on wholesale
transactions are shared with the customers. This sharing is recognized through
credits to fuel expense. As margins on wholesale electricity marketing and
trading transactions declined, the amount of credits shared through the fuel
clause adjustment mechanism decreased.
The decreases in purchased power expense were attributable to lower
prices resulting from general market trends and reduced volume of electricity
traded stemming from continued soft demand in the wholesale power market.
Other operation expense decreased due to reduced consumption of emission
allowances, increased AEP transmission equalization credits and reduced accruals
for trading incentive compensation. Under the AEP East Region Transmission
Agreement, KPCo and certain affiliates share the costs associated with the
ownership of their transmission system based upon each company' peak demand and
investment. A decrease in KPCo's peak demand relative to its affiliates' peak
demand was the main reason for the increase in transmission equalization
credits.
Maintenance expense increased as a result of planned power plant
outages.
Taxes other than income taxes increased with increases in payroll taxes
and real and personal property taxes. Income taxes year-to-date have increased
primarily as a result of increases in pre-tax income.
Decreases in nonoperating income and expenses were due to decreases 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.
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $276,723 $396,250 $586,880 $809,383
Energy Delivery 31,385 30,837 66,514 67,164
Sales to AEP Affiliates 8,893 12,044 14,915 21,741
-------- -------- -------- --------
TOTAL OPERATING REVENUES 317,001 439,131 668,309 898,288
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 17,570 17,418 39,337 35,374
Purchased Power:
Electricity Marketing and Trading 224,647 349,388 476,652 707,618
AEP Affiliates 32,366 32,525 61,307 68,160
Other Operation 12,811 14,470 25,280 29,198
Maintenance 8,078 5,185 12,627 10,614
Depreciation and Amortization 8,269 8,080 16,526 16,107
Taxes Other Than Income Taxes 2,368 1,900 4,503 3,949
Income Taxes 1,342 1,801 7,043 6,300
-------- -------- -------- --------
TOTAL OPERATING EXPENSES 307,451 430,767 643,275 877,320
-------- -------- -------- --------
OPERATING INCOME 9,550 8,364 25,034 20,968
NONOPERATING INCOME 108,733 158,973 210,717 272,489
NONOPERATING EXPENSES 104,604 157,076 205,516 268,349
NONOPERATING INCOME TAX EXPENSE 1,920 654 1,730 1,422
INTEREST CHARGES 6,513 6,865 13,013 13,869
-------- -------- -------- --------
NET INCOME $ 5,246 $ 2,742 $ 15,492 $ 9,817
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $5,246 $2,742 $15,492 $ 9,817
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Power Hedge 572 - 572 -
Cash Flow Interest Rate Hedge 357 (68) 873 (1,422)
------ ------ ------- -------
COMPREHENSIVE INCOME $6,175 $2,674 $16,937 $ 8,395
====== ====== ======= =======
The common stock of KPCo 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 June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $52,035 $57,027 $48,833 $57,513
NET INCOME 5,246 2,742 15,492 9,817
DEDUCTIONS:
Cash Dividends Declared 7,044 7,561 14,088 15,122
------- ------- ------- -------
BALANCE AT END OF PERIOD $50,237 $52,208 $50,237 $52,208
======= ======= ======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 273,037 $ 271,070
Transmission 373,339 374,116
Distribution 405,503 402,537
General 63,671 65,059
Construction Work in Progress 59,796 15,633
---------- ----------
Total Electric Utility Plant 1,175,346 1,128,415
Accumulated Depreciation and Amortization 394,818 384,104
---------- ----------
NET ELECTRIC UTILITY PLANT 780,528 744,311
---------- ----------
OTHER PROPERTY AND INVESTMENTS 6,354 6,492
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 126,702 77,972
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 918 1,947
Advances to Affiliates 2,165 -
Accounts Receivable:
Customers 23,516 20,036
Affiliated Companies 40,179 16,012
Miscellaneous 2,707 3,333
Allowance for Uncollectible Accounts (241) (264)
Fuel - at average cost 17,479 12,060
Materials and Supplies - at average cost 16,828 15,766
Accrued Utility Revenues 7,813 5,395
Energy Trading Contracts 204,908 139,605
Prepayments 3,212 1,314
---------- ----------
TOTAL CURRENT ASSETS 319,484 215,204
---------- ----------
REGULATORY ASSETS 97,615 97,692
---------- ----------
DEFERRED CHARGES 10,217 11,572
---------- ----------
TOTAL ASSETS $1,340,900 $1,153,243
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 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) (458) (1,903)
Retained Earnings 50,237 48,833
---------- ----------
Total Common Shareowner's Equity 258,979 256,130
Long-term Debt 300,796 251,093
---------- ----------
TOTAL CAPITALIZATION 559,775 507,223
---------- ----------
OTHER NONCURRENT LIABILITIES 12,348 11,929
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 155,000 95,000
Advances from Affiliates - 66,200
Accounts Payable:
General 32,325 24,050
Affiliated Companies 38,892 22,557
Customer Deposits 6,877 4,461
Taxes Accrued 10,434 10,305
Interest Accrued 4,644 5,269
Energy Trading Contracts 203,518 144,364
Other 14,981 12,296
---------- ----------
TOTAL CURRENT LIABILITIES 466,671 384,502
---------- ----------
DEFERRED INCOME TAXES 169,770 168,304
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 9,814 10,405
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 111,507 63,412
---------- ----------
DEFERRED CREDITS 11,015 7,468
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,340,900 $1,153,243
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 15,492 $ 9,817
Adjustments for Noncash Items:
Depreciation and Amortization 16,526 16,107
Deferred Income Taxes 965 7,921
Deferred Investment Tax Credits (591) (593)
Deferred Fuel Costs (net) 2,430 (1,241)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (27,044) 4,012
Fuel, Materials and Supplies (6,481) (672)
Accrued Utility Revenues (2,418) 6,500
Accounts Payable 24,610 3,245
Taxes Accrued 129 (6,606)
Mark-to-Market Energy Contracts (4,479) (21,923)
Change in Other Assets (1,416) 2,336
Change in Other Liabilities 6,355 (4,841)
-------- --------
Net Cash Flows From Operating Activities 24,078 14,062
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures (51,997) (14,912)
Proceeds from Sales of Property - 216
-------- --------
Net Cash Flow Used For Investing Activities (51,997) (14,696)
-------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - Affiliated Company 123,843 75,000
Retirement of Long-term Debt (14,500) (60,000)
Change in Advances from Affiliates (net) (68,365) (405)
Dividends Paid (14,088) (15,122)
-------- --------
Net Cash Flows From (Used For) Financing Activities 26,890 (527)
-------- --------
Net Decrease in Cash and Cash Equivalents (1,029) (1,161)
Cash and Cash Equivalents at Beginning of Period 1,947 2,270
-------- --------
Cash and Cash Equivalents at End of Period $ 918 $ 1,109
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $13,485,000 and
$13,692,000 and for income taxes was $7,024,000 and $6,010,000 in 2002 and 2001,
respectively. Noncash acquisitions under capital leases were $22,021 and
$760,000 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
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 $44.8 million in the second quarter of 2002 and
$55.4 million in the year-to-date period due to the effect of an extraordinary
loss recorded in the second quarter of 2001 to recognize a stranded asset
resulting from deregulation.
The decline in revenues is mainly due to a decrease in electric
marketing and trading revenues due to lower wholesale energy prices. In 2002 the
wholesale energy sector has been under pressure from lower commodity prices in
contrast to last year when we had strong performance from the wholesale business
due to favorable market conditions.
The following analyzes the changes in operating revenues:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
and Trading* $(337) (25) $(632) (23)
Energy Delivery* 10 7 20 8
Sales to AEP Affiliates (4) (3) (36) (13)
----- -----
Total $(331) (20) $(648) (19)
===== =====
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
Operating expenses declined 22% in the second quarter of 2002 and 21% in
the year-to-date period of 2002. The changes in the components of operating
expenses were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $(31) (17) $ (89) (23)
Electricity Marketing
and Trading Purchases (341) (30) (623) (27)
Purchases from AEP Affiliates 4 22 1 4
Other Operation 10 10 12 7
Maintenance (7) (18) (13) (18)
Depreciation and Amortization 3 6 6 5
Taxes Other Than Income Taxes (1) (3) 4 5
Income Taxes 17 94 21 42
---- -----
Total $(346) (22) $(681) (21)
===== =====
The fuel expense decrease reflects a reduction of 17% in the average
cost fuel for generation offset in part by a 10% increase in MWH generated.
Electricity marketing and trading purchases declined due to lower
wholesale energy costs driven by market conditions.
Other operation expense increased in both periods primarily due to post
retirement benefits expense.
Maintenance expenses decreased in the second quarter and year-to-date
of 2002 due to boiler overhaul work that was performed during 2001.
Depreciation expense increased in both periods due to the placement of
selective catalytic reduction (SCR) technology in service at the Gavin Plant in
the second quarter of 2001.
The increase in income taxes for both periods is predominately due to an
increase in pre-tax income.
The decrease in nonoperating income as well as a decrease in
nonoperating 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.
The decrease in interest was primarily due to a slightly smaller
decrease in the outstanding balances of long-term debt in both periods as
compared to year end balances in both periods, the refinancing of debt at
favorable interest rates and a reduction in short-term interest rates.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $1,027,105 $1,364,271 $2,159,297 $2,791,088
Energy Delivery 143,144 133,160 284,904 265,009
Sales to AEP Affiliates 125,393 129,746 235,027 270,745
---------- ---------- ---------- ----------
TOTAL OPERATING REVENUES 1,295,642 1,627,177 2,679,228 3,326,842
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 149,097 180,057 291,433 380,618
Purchased Power:
Electricity Marketing and Trading 789,191 1,130,038 1,669,348 2,292,322
AEP Affiliates 20,265 16,617 34,492 33,239
Other Operation 106,633 96,623 197,153 185,029
Maintenance 29,957 36,448 58,945 71,848
Depreciation and Amortization 61,176 57,666 123,797 117,725
Taxes Other Than Income Taxes 43,292 44,662 89,131 84,898
Income Taxes 34,985 17,999 70,167 49,340
---------- ---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,234,596 1,580,110 2,534,466 3,215,019
---------- ---------- ---------- ----------
OPERATING INCOME 61,046 47,067 144,762 111,823
NONOPERATING INCOME 381,184 538,032 737,525 908,506
NONOPERATING EXPENSES 366,062 528,734 716,885 885,592
NONOPERATING INCOME TAX EXPENSE 626 1,489 4,348 3,997
INTEREST CHARGES 20,194 22,782 41,655 45,249
---------- ---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 55,348 32,094 119,399 85,491
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION (INCLUSIVE OF TAX BENEFIT
OF $11,585,000) - (21,515) - (21,515)
---------- ---------- -------- ----------
NET INCOME 55,348 10,579 119,399 63,976
PREFERRED STOCK DIVIDEND REQUIREMENTS 315 316 629 630
---------- ---------- -------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 55,033 $ 10.263 $118,770 $ 63,346
========== ========== ======== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $55,348 $10,579 $119,399 $63,976
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge - - (201) -
Cash Flow Power Hedges 1,970 (104) 1,970 (325)
------- ------- -------- -------
COMPREHENSIVE INCOME $57,318 $10,475 $121,168 $63,651
======= ======= ======== =======
The common stock of Ohio Power 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 June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $432,452 $415,425 $401,297 $398,086
NET INCOME 55,348 10,579 119,399 63,976
CASH DIVIDENDS DECLARED:
Common Stock 32,582 35,744 65,164 71,488
Cumulative Preferred Stock 315 315 629 629
-------- -------- -------- --------
BALANCE AT END OF PERIOD $454,903 $389,945 $454,903 $389,945
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $3,032,034 $3,007,866
Transmission 891,591 891,283
Distribution 1,095,478 1,081,122
General 238,903 245,232
Construction Work in Progress 264,296 165,073
---------- ----------
Total Electric Utility Plant 5,522,302 5,390,576
Accumulated Depreciation and Amortization 2,513,727 2,452,571
---------- ----------
NET ELECTRIC UTILITY PLANT 3,008,575 2,938,005
---------- ----------
OTHER PROPERTY AND INVESTMENTS 59,958 62,303
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 438,789 263,734
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 6,872 8,848
Accounts Receivable:
Customers 103,425 84,694
Affiliated Companies 193,372 148,563
Miscellaneous 22,937 20,409
Allowance for Uncollectible Accounts (678) (1,379)
Fuel - at average cost 87,396 84,724
Materials and Supplies - at average cost 81,625 88,768
Accrued Utility Revenues 5,276 -
Energy Trading Contracts 711,726 472,246
Prepayments and Other 36,624 20,865
---------- ----------
TOTAL CURRENT ASSETS 1,248,575 927,738
---------- ----------
REGULATORY ASSETS 611,696 644,625
---------- ----------
DEFERRED CHARGES 42,290 79,662
---------- ----------
TOTAL ASSETS $5,409,883 $4,916,067
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 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) 1,573 (196)
Retained Earnings 454,903 401,297
---------- ----------
Total Common Shareholder's Equity 1,240,160 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 974,350 1,203,841
---------- ----------
TOTAL CAPITALIZATION 2,240,008 2,414,124
---------- ----------
OTHER NONCURRENT LIABILITIES 130,298 130,386
---------- ----------
CURRENT LIABILITIES:
Short-term Debt From Affiliated Companies 150,000 -
Long-term Debt Due Within One Year 224,850 -
Advances from Affiliates 137,069 300,213
Accounts Payable - General 131,398 134,418
Accounts Payable - Affiliated Companies 274,557 176,520
Customer Deposits 9,037 5,452
Taxes Accrued 141,044 126,770
Interest Accrued 21,965 17,679
Obligations Under Capital Leases 14,346 16,405
Energy Trading Contracts 673,621 456,047
Other 56,250 87,070
---------- ----------
TOTAL CURRENT LIABILITIES 1,834,137 1,320,574
---------- ----------
DEFERRED INCOME TAXES 781,270 797,889
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 20,395 21,925
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 382,253 214,487
---------- ----------
DEFERRED CREDITS 21,522 16,682
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,409,883 $4,916,067
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 119,399 $ 63,976
Adjustments for Noncash Items:
Depreciation 86,605 93,161
Amortization of Transition Assets 37,192 36,705
Deferred Federal Income Taxes (18,653) 116
Mark-to-Market Energy Trading Contracts (24,493) (69,557)
Deferred Property Taxes 30,046 40,596
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (66,769) (37,904)
Fuel, Materials and Supplies 4,471 2,252
Accrued Utility Revenues (5,276) 264
Prepayments and Other Current Assets (15,759) 15,116
Accounts Payable 95,017 (62,996)
Customer Deposits 3,585 (32,368)
Taxes Accrued 14,274 (39,022)
Interest Accrued 4,286 3,841
Other Operating Assets 6,667 15,877
Other Operating Liabilities (30,834) (44,004)
--------- ---------
Net Cash Flows From (Used For) Operating Activities 239,758 (13,947)
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (158,080) (151,314)
Proceeds from Sale of Property and Other 283 7,626
--------- ---------
Net Cash Flows Used For Investing Activities (157,797) (143,688)
--------- ---------
FINANCING ACTIVITIES:
Change in Advances to Affiliates (net) (163,144) 344,809
Retirement of Long-term Debt (5,000) (117,506)
Change in Short-term Debt Affiliated (net) 150,000 -
Dividends Paid on Common Stock (65,164) (71,488)
Dividends Paid on Cumulative Preferred Stock (629) (630)
--------- ---------
Net Cash Flows From (Used For) Financing Activities (83,937) 155,185
--------- ---------
Net Decrease in Cash and Cash Equivalents (1,976) (2,450)
Cash and Cash Equivalents at Beginning of Period 8,848 31,393
--------- ---------
Cash and Cash Equivalents at End of Period $ 6,872 $ 28,943
========= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $36,585,000 and
$40,580,000 and for income taxes was $29,187,000 and $54,694,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $98,000 and
$522,000 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
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 AEP's 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
Net income declined by 2.5% for the quarter and 4% for the year-to-date
period as substantial decreases in revenues were nearly offset by comparable
decreases in operating expenses.
The following analyzes the changes in operating revenues:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
and Trading* $(153) (47) $(256) (41)
Energy Delivery* 10 16 13 12
Sales to AEP Affiliates (2) (19) (11) (56)
----- -----
Total $(145) (36) $(254) (34)
===== =====
*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 AEP marketing and trading revenues shared with PSO.
Revenues from AEP's power marketing and trading operations declined as a result
of lower prices for wholesale power transactions. In 2002 the wholesale energy
sector has been under pressure from lower commodity prices in contrast to last
year when we had strong performance from the wholesale business due to favorable
market conditions.
Significant change in operating expenses are as follows:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $(112) (77) $(166) (64)
Electricity Marketing
and Trading Purchases (44) (35) (77) (30)
Purchases from AEP Affiliates 12 53 (8) (14)
Other Operation - - (7) (11)
Maintenance (1) (8) 3 15
Depreciation and Amortization 1 7 3 7
The decrease in fuel expense was primarily due to amortization of
previously overrecovered fuel costs through the fuel clause recovery mechanism
and a reduction in the cost of fuel reflecting lower market prices for natural
gas and fuel oil.
The decrease in electric marketing and trading purchases resulted
mainly from the decrease in energy prices.
The increase in the quarter and the decrease year-to-date in purchases
from AEP affiliates results mainly from the availability of internal generation.
Other operation expense decreased in the year-to-date period primarily
due to lower transmission, administrative, and customer service expenses.
Maintenance expense decreased in the second quarter due primarily to
lower production power plant costs and distribution costs for overhead and
underground facilities. Year-to-date 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 for both the quarter and year-to-date
due to the cost of repowering Northeast Station Units 1 & 2.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $175,999 $ 329,316 $370,023 $ 625,915
Energy Delivery 70,815 61,294 122,547 109,711
Sales to AEP Affiliates 6,162 7,584 8,256 18,707
-------- ---------- -------- ----------
TOTAL OPERATING REVENUES 252,976 398,194 500,826 754,333
-------- ---------- -------- ----------
OPERATING EXPENSES:
Fuel 33,772 145,927 91,869 257,728
Purchased Power:
Electricity Marketing and Trading 81,803 126,602 178,323 255,781
AEP Affiliates 34,703 22,659 51,548 60,026
Other Operation 34,826 34,332 61,465 68,889
Maintenance 11,886 12,859 26,055 22,689
Depreciation and Amortization 21,061 19,673 41,977 39,144
Taxes Other Than Income Taxes 8,083 7,533 15,931 15,326
Income Taxes 6,641 6,667 5,047 4,468
-------- ---------- -------- ----------
TOTAL OPERATING EXPENSES 232,775 376,252 472,215 724,051
-------- ---------- -------- ----------
OPERATING INCOME 20,201 21,942 28,611 30,282
NONOPERATING INCOME 1,223 409 1,329 1,233
NONOPERATING EXPENSES 69 336 664 672
NONOPERATING INCOME TAX CREDIT (100) (19) (241) (134)
INTEREST CHARGES 9,835 10,113 19,545 20,616
-------- ---------- -------- ----------
NET INCOME 11,620 11,921 9,972 10,361
PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53 106 106
-------- ---------- -------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 11,567 $ 11.868 $ 9,866 $ 10,255
======== ========== ======== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $11,620 $11,921 $ 9,972 $10,361
OTHER COMPREHENSIVE INCOME
Cash Flow Power Hedge 200 - 200 -
------- ------- ------- -------
COMPREHENSIVE INCOME $11,820 $11,921 $10,172 $10,361
======= ======= ======= =======
The common stock of the Company is wholly owned by AEP. See Notes to Financial
Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $118,838 $123,015 $142,994 $137,688
NET INCOME 11,620 11,921 9,972 10,361
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 22,456 13,060 44,911 26,120
Preferred Stock 53 53 106 106
-------- -------- -------- --------
BALANCE AT END OF PERIOD $107,949 $121,823 $107,949 $121,823
======== ======== ======== ========
The common stock of the Company 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)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,040,461 $1,034,711
Transmission 432,990 427,110
Distribution 990,374 972,806
General 203,088 203,572
Construction Work in Progress 58,004 56,900
---------- ----------
Total Electric Utility Plant 2,724,917 2,695,099
Accumulated Depreciation and Amortization 1,219,697 1,184,443
---------- ----------
NET ELECTRIC UTILITY PLANT 1,505,220 1,510,656
---------- ----------
OTHER PROPERTY AND INVESTMENTS 42,383 41,020
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 22,015 55,215
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 6,953 5,795
Accounts Receivable:
Customers 35,896 31,100
Affiliated Companies 30,061 10,905
Fuel - at LIFO costs 24,939 21,559
Materials and Supplies - at average costs 36,631 36,785
Under-Recovered Fuel Costs 44,436 -
Energy Trading Contracts 41,417 162,200
Prepayments and Other 2,343 2,368
---------- ----------
TOTAL CURRENT ASSETS 222,676 270,712
---------- ----------
REGULATORY ASSETS 26,428 35,004
---------- ----------
DEFERRED CHARGES 26,152 5,290
---------- ----------
TOTAL ASSETS $1,844,874 $1,917,897
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 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
Accumulated Other Comprehensive Income 200 -
Retained Earnings 107,949 142,994
---------- ----------
Total Common Shareholder's Equity 445,379 480,224
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 310,283 345,129
---------- ----------
TOTAL CAPITALIZATION 835,945 905,636
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 141,000 106,000
Advances from Affiliates 212,950 123,087
Accounts Payable - General 62,987 72,759
Accounts Payable - Affiliated Companies 76,447 40,857
Customers Deposits 21,869 21,041
Taxes Accrued 15,962 18,150
Over-Recovered Fuel Costs - 8,720
Interest Accrued 3,331 7,298
Energy Trading Contracts 47,305 167,658
Other 17,262 12,296
---------- ----------
TOTAL CURRENT LIABILITIES 599,113 577,866
---------- ----------
DEFERRED INCOME TAXES 319,339 296,877
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 33,097 33,992
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 37,170 56,203
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 20,210 47,323
---------- ----------
TOTAL CAPITALIZATION AND LIABILITIES $1,844,874 $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)
Six Months Ended June 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 9,972 $ 10,361
Adjustments for Noncash Items:
Depreciation and Amortization 41,977 39,144
Deferred Income Taxes 21,559 (10,754)
Deferred Investment Tax Credits (895) (895)
Deferred Property Taxes (16,184) (14,951)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (23,952) 17,488
Fuel, Materials and Supplies (3,226) 6,094
Accounts Payable 25,818 (52,882)
Taxes Accrued (2,188) 28,006
Fuel Recovery (53,156) 31,748
Changes in Other Assets (2,968) (8,234)
Changes in Other Liabilities (4,387) 1,780
--------- --------
Net Cash Flows From (Used For) Operating Activities (7,630) 46,905
--------- --------
INVESTING ACTIVITIES:
Construction Expenditures (35,095) (67,042)
Other (963) (359)
--------- --------
Net Cash Flows Used For Investing Activities (36,058) (67,401)
--------- --------
FINANCING ACTIVITIES:
Retirement of Long-term Debt - (20,000)
Change in Advances From Affiliates (net) 89,863 66,327
Dividends Paid on Common Stock (44,911) (26,120)
Dividends Paid on Cumulative Preferred Stock (106) (106)
--------- --------
Net Cash Flows From Financing Activities 44,846 20,101
--------- --------
Net Increase in Cash and Cash Equivalents 1,158 (395)
Cash and Cash Equivalents at Beginning of Period 5,795 11,301
--------- --------
Cash and Cash Equivalents at End of Period $ 6,953 $ 10,906
========= ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $17,870,000 and
$19,011,000 and for income taxes was $2,575,000 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
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 increased slightly in the second quarter and decreased $11
million or 30%, for the first half of 2002. The decrease for the first half of
2002 resulted from reduced wholesale prices and margins due to a decline in
demand for electricity which resulted from mild weather and a slow economic
recovery.
Operating revenues decreased 19% in the second quarter and 20% for the
year-to-date period due to decreased wholesale marketing and trading prices. The
changes in the components of revenues were as follows:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
and Trading* $(74.7) (23) $(153.3) (24)
Energy Delivery* (2.0) (2) (11.1) (7)
Sales to AEP Affiliates (4.5) (24) (10.2) (22)
------ -------
Total $(81.2) (19) $(174.6) (20)
====== =======
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
All of the components of revenues decreased in 2002 as a result of
reduced wholesale prices due to reduced energy demand as a result of a
decrease in marketing and trading activity, and the slow economic recovery.
Operating expenses decreased 20% in the second quarter and the
year-to-date period due to a significant decrease in electricity marketing and
trading purchases and fuel expense.
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $(28.9) (23) $ (58.3) (24)
Electricity Marketing
and Trading Purchases (60.3) (38) (104.0) (33)
Purchases from AEP Affiliates - - (5.6) (21)
Other Operation 10.7 31 13.5 18
Maintenance 0.5 3 (2.9) (8)
Depreciation and Amortization (2.8) (8) (0.7) (1)
Taxes Other Than Income Taxes (0.6) (4) 0.8 3
Income Taxes 1.3 16 (4.8) (29)
------ -------
Total $(80.1) (20) $(162.0) (20)
====== =======
Fuel expense decreased due to lower natural gas prices as a result of a
mild winter and the slow economic recovery.
Decreasing purchased power prices resulted in decreases to both
electricity marketing and trading purchases and electricity purchases from AEP
affiliates for the second quarter and first half of 2002. The first half of 2002
was also affected by milder than normal winter.
The acquisition of Dolet Hills mining operation in June 2001 caused
other operation expense to increase in 2002.
Maintenance expense decreased for the first half of 2002 as a result of
costs incurred last year to restore service and make repairs following a severe
ice storm.
The decrease in depreciation and amortization expense was due primarily
to a decrease in excess earnings accruals under the Texas restructuring
legislation offset by new expenses from the acquisition of the Dolet Hills
mining operation.
The increase in income taxes for the second quarter of 2002 is
predominately due to the reversal of deferred taxes in excess of the statutory
tax rate, and an increase in pre-tax income. Income taxes attributable to
operations decreased for the first half of 2002 due to a significant decrease in
pre-tax income.
Nonoperating income decreased for the first half of 2002 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
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.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $255,385 $330,094 $495,730 $649,080
Energy Delivery 84,008 85,970 152,943 164,027
Sales to AEP Affiliates 14,224 18,731 37,184 47,377
-------- -------- -------- --------
TOTAL OPERATING REVENUES 353,617 434,795 685,857 860,484
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 95,207 124,151 184,090 242,397
Purchased Power:
Electricity Marketing and Trading 96,349 156,608 207,444 311,403
AEP Affiliates 12,075 12,063 20,516 26,125
Other Operation 44,725 34,071 86,876 73,339
Maintenance 20,942 20,431 32,780 35,667
Depreciation and Amortization 30,533 33,328 60,673 61,458
Taxes Other Than Income Taxes 12,889 13,485 27,355 26,513
Income Taxes 9,317 8,009 12,074 16,947
-------- -------- -------- --------
TOTAL OPERATING EXPENSES 322,037 402,146 631,808 793,849
-------- -------- -------- --------
OPERATING INCOME 31,580 32,649 54,049 66,635
NONOPERATING INCOME 313 850 415 1,683
NONOPERATING EXPENSES (CREDITS) (20) 681 546 1,320
NONOPERATING INCOME TAX EXPENSE
(CREDIT) (137) 139 (109) 86
INTEREST CHARGES 13,895 14,895 27,713 29,259
-------- -------- -------- --------
NET INCOME 18,155 17,784 26,314 37,653
-------- -------- -------- --------
PREFERRED STOCK DIVIDEND REQUIREMENTS 58 58 115 115
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 18,097 $ 17,726 $ 26,199 $ 37,538
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $18,155 $17,784 $26,314 $37,653
OTHER COMPREHENSIVE INCOME
Cash Flow Power Hedge 230 - 230 -
------- ------- ------- -------
COMPREHENSIVE INCOME $18,385 $17,784 $26,544 $37,653
======= ======= ======= =======
The common stock of SWEPCo is wholly owned by AEP. See Notes to Financial
Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $298,053 $295,248 $308,915 $293,989
NET INCOME 18,155 17,784 26,314 37,653
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 18,963 18,552 37,927 37,105
Preferred Stock 58 58 115 115
-------- -------- -------- --------
BALANCE AT END OF PERIOD $297,187 $294,422 $297,187 $294,422
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,443,282 $1,429,356
Transmission 565,230 538,749
Distribution 1,036,036 1,042,523
General 394,628 376,016
Construction Work in Progress 51,488 74,120
---------- ----------
Total Electric Utility Plant 3,490,664 3,460,764
Accumulated Depreciation and Amortization 1,606,606 1,550,618
---------- ----------
NET ELECTRIC UTILITY PLANT 1,884,058 1,910,146
---------- ----------
OTHER PROPERTY AND INVESTMENTS 44,127 43,000
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 25,267 63,372
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 15,860 5,415
Accounts Receivable:
Customers 51,533 44,588
Affiliated Companies 60,171 12,069
Allowance for Uncollectible Accounts (111) (89)
Fuel Inventory - at average cost 78,335 52,212
Under-recovered Fuel - 2,501
Materials and Supplies - at average cost 36,932 32,527
Energy Trading Contracts 47,535 186,159
Prepayments 18,993 18,716
---------- ----------
TOTAL CURRENT ASSETS 309,248 354,098
---------- ----------
REGULATORY ASSETS 48,165 51,989
---------- ----------
DEFERRED CHARGES 79,693 67,753
---------- ----------
TOTAL ASSETS $2,390,558 $2,490,358
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 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
Accumulated Other Comprehensive Income 230 -
Retained Earnings 297,187 308,915
---------- ----------
Total Common Shareowner's Equity 678,077 689,575
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 637,810 494,688
---------- ----------
TOTAL CAPITALIZATION 1,430,591 1,298,967
---------- ----------
OTHER NONCURRENT LIABILITIES 14,617 34,997
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 55,595 150,595
Advances from Affiliates 65,073 117,367
Accounts Payable - General 89,147 71,810
Accounts Payable - Affiliated Companies 94,789 37,469
Customer Deposits 19,446 19,880
Taxes Accrued 61,162 36,522
Interest Accrued 11,473 13,631
Energy Trading Contracts 54,187 192,318
Over-recovered Fuel 9,146 -
Other 16,275 26,166
---------- ----------
TOTAL CURRENT LIABILITIES 476,293 665,758
---------- ----------
DEFERRED INCOME TAXES 361,712 369,781
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 46,452 48,714
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 37,754 17,828
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 23,139 54,313
---------- ----------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $2,390,558 $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)
Six Months Ended June 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 26,314 $ 37,653
Adjustments for Noncash Items:
Depreciation and Amortization 60,673 61,458
Deferred Income Taxes (9,004) (4,546)
Deferred Investment Tax Credits (2,262) (2,212)
Mark-to-Market Energy Trading Contracts 7,834 (7,942)
Deferred Property Taxes (17,545) (17,703)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (55,025) 2,286
Fuel, Materials and Supplies (30,528) (4,266)
Accounts Payable 74,657 (45,226)
Taxes Accrued 24,640 41,158
Fuel Recovery 11,647 (9,447)
Change in Other Assets 10,995 (47,147)
Change in Other Liabilities (13,802) 49,536
--------- ---------
Net Cash Flows From Operating Activities 88,594 53,602
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (35,695) (49,418)
Purchase of Dolet Hills - (85,716)
Other (284) (411)
--------- ---------
Net Cash Flows Used For Investing Activities (35,979) (135,545)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 198,616 -
Retirement of Long-term Debt (150,450) (450)
Change in Advances from Affiliates (net) (52,294) 119,660
Dividends Paid on Common Stock (37,927) (37,105)
Dividends Paid on Cumulative Preferred Stock (115) (115)
--------- ---------
Net Cash Flows From (Used For) Financing Activities (42,170) 81,990
--------- ---------
Net Increase in Cash and Cash Equivalents 10,445 47
Cash and Cash Equivalents at Beginning of Period 5,415 1,907
--------- ---------
Cash and Cash Equivalents at End of Period $ 15,860 $ 1,954
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $21,331,000 and
$25,743,000 and for income taxes was $24,479,000 and $4,144,000 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
SECOND QUARTER 2002 vs. SECOND QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 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 Southwest Power Pool (SPP) 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 that was unbundled from WTU and also sells its
generation to other REPs in the area. 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 the "Quantitative and
Qualitative Disclosures about Market Risk" section of Part I, Item 2 for a
discussion of the policies and procedures used to manage exposure to risk from
trading activities.
Results of Operations
Net income decreased $5.5 million or 89% for the quarter and $2.4
million or 34% for the year-to-date period. The decreases are primarily due to a
downturn in the overall economy, a significant decline in wholesale prices, and
the diversion of retail sales from the ultimate retail customer to the REPs in
the ERCOT region as of January 1, 2002.
Overall operating revenues decreased $50.8 million for the quarter and
$104.6 million year-to-date as shown below:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing
and Trading* $(92) (63) $(192) (65)
Energy Delivery* (4) (10) (2) (3)
Sales to AEP Affiliates 45 N.M. 89 N.M.
---- -----
Total $(51) (26) $(105) (27)
==== =====
*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
primarily as a result of the elimination of retail electricity sales in the
ERCOT region as of January 1, 2002. Also contributing to the decrease was a
decline in prices for power trading transactions. In 2002 the wholesale energy
sector has been under pressure from lower commodity prices in contrast to last
year when we had strong performance from the wholesale business due to favorable
market conditions. Sales to AEP affiliates increased primarily due to increased
revenues to the newly-created affiliated REP. Although WTU sold electricity to
the affiliated REP instead of directly to retail customers in the ERCOT region,
total revenues received were lower because of the lower wholesale prices.
Operating expenses declined $43.7 million for the quarter and $103.3
million year-to-date, primarily due to decreases in fuel expense and purchased
power. Changes in the components of operating expenses are shown below:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $(14) (30) $ (49) (46)
Electricity Marketing and
Trading Purchases (19) (29) (36) (29)
Purchases from AEP Affiliates (6) (37) (15) (40)
Other Operation - - (2) (4)
Maintenance - - - -
Depreciation and Amortization (1) (4) (1) (3)
Taxes Other Than Income Taxes (1) (9) - -
Income Taxes (3) (116) - -
---- -----
Total $(44) (24) $(103) (28)
==== =====
Fuel expense decreased significantly primarily due to a decrease in the
average unit cost of fuel as a result of lower spot market natural gas prices.
The decline in electricity marketing and trading purchases was mainly
due to reduced prices caused by decreased electricity demand driven largely by
the downturn in the economy.
The quarter-to-date decrease in income taxes is predominately due to a
decrease in pre-tax income.
Nonoperating income and expense increased significantly during the
quarter and year-to-date as a result of increased non-utility revenue and
expenses associated with energy related construction projects for third parties.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $ 53,681 $145,720 $104,046 $296,061
Energy Delivery 38,550 42,688 79,179 81,330
Sales to AEP Affiliates 49,798 4,431 100,040 10,454
-------- -------- -------- --------
Total Operating Revenues 142,029 192,839 283,265 387,845
OPERATING EXPENSES:
Fuel 32,842 46,848 57,822 106,753
Purchased Power:
Electricity Marketing and Trading 44,989 63,650 89,112 124,950
AEP Affiliates 10,559 16,835 22,209 37,227
Other Operation 24,910 25,355 49,080 51,111
Maintenance 7,050 7,046 11,406 11,608
Depreciation and Amortization 11,072 11,529 22,641 23,300
Taxes Other Than Income Taxes 5,726 6,260 12,026 12,298
Income Taxes (Credit) (468) 2,888 2,475 2,778
-------- -------- -------- --------
Total Operating Expenses 136,680 180,411 266,771 370,025
OPERATING INCOME 5,349 12,428 16,494 17,820
NONOPERATING INCOME 6,980 253 5,492 2,298
NONOPERATING EXPENSES 5,688 188 7,060 520
NONOPERATING INCOME TAX EXPENSE
(CREDIT) 358 618 (631) 900
INTEREST CHARGES 5,608 5,742 10,890 11,674
-------- -------- -------- --------
NET INCOME 675 6,133 4,667 7,024
PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26 52 52
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 649 $ 6,107 $ 4,615 $ 6,972
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $675 $6,133 $4,667 $7,024
OTHER COMPREHENSIVE INCOME
Cash Flow Power Hedge 78 - 78 -
---- ------ ------ ------
COMPREHENSIVE INCOME $753 $6,133 $4,745 $7,024
==== ====== ====== ======
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
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $103,187 $116,247 $105,970 $122,588
NET INCOME 675 6,133 4,667 7,024
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 6,749 7,206 13,498 14,412
Preferred Stock 26 26 52 52
-------- -------- -------- --------
BALANCE AT END OF PERIOD $ 97,087 $115,148 $ 97,087 $115,148
======== ======== ======== ========
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)
June 30, 2002 December 31, 2001
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 442,670 $ 443,508
Transmission 254,463 250,023
Distribution 440,271 431,969
General 108,642 112,797
Construction Work in Progress 32,115 22,575
---------- ----------
Total Electric Utility Plant 1,278,161 1,260,872
Accumulated Depreciation and Amortization 557,728 546,162
---------- ----------
NET ELECTRIC UTILITY PLANT 720,433 714,710
---------- ----------
OTHER PROPERTY AND INVESTMENTS 25,329 24,933
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 12,985 21,532
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 1,908 2,454
Accounts Receivable:
Customers 29,200 18,720
Affiliated Companies 72,975 8,656
Allowance for Uncollectible Accounts (219) (196)
Fuel - at average cost 10,038 8,307
Materials and Supplies - at average cost 4,464 11,190
Under-recovered Fuel Costs 34,842 32,791
Energy Trading Contracts 25,156 63,252
Prepayments and Other Current Assets 1,655 966
---------- ----------
TOTAL CURRENT ASSETS 180,019 146,140
---------- ----------
REGULATORY ASSETS 10,392 13,659
---------- ----------
DEFERRED CHARGES 25,717 2,446
---------- ----------
TOTAL ASSETS $ 974,875 $ 923,420
========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 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
Accumulated Other Comprehensive Income 78 -
Retained Earnings 97,087 105,970
-------- --------
Total Common Shareowner's Equity 236,615 245,420
Cumulative Preferred Stock Not Subject to
Mandatory Redemption 2,482 2,482
Long-term Debt 221,028 220,967
-------- --------
TOTAL CAPITZALIZATION 460,125 468,869
-------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 35,000 35,000
Advances from Affiliates 120,439 50,448
Accounts Payable - General 19,129 33,782
Accounts Payable - Affiliated Companies 64,024 11,388
Customer Deposits - 4,191
Taxes Accrued 18,503 17,358
Interest Accrued - 1,244
Energy Trading Contracts 24,759 65,414
Other 15,890 12,001
-------- --------
TOTAL CURRENT LIABILITIES 297,744 230,826
-------- --------
DEFERRED INCOME TAXES 147,088 145,049
-------- --------
DEFERRED INVESTMENT TAX CREDITS 22,145 22,781
-------- --------
LONG-TERM ENERGY TRADING CONTRACTS 11,212 18,455
-------- --------
REGULATORY LIABILITIES AND DEFERRED CREDITS 36,561 37,440
-------- --------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $974,875 $923,420
======== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2002 2001
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 4,667 $ 7,024
Adjustments for Noncash Items:
Depreciation and Amortization 22,641 23,300
Deferred Income Taxes 1,470 (4,738)
Deferred Investment Tax Credits (636) (636)
Mark-to-Market Energy Trading Contracts (1,134) (2,639)
Deferred Property Taxes (7,175) (6,200)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (74,776) 24,941
Fuel, Materials and Supplies 4,995 (3,276)
Accounts Payable 37,983 (42,805)
Taxes Accrued 1,145 13,305
Fuel Recovery (2,051) 8,978
Change in Other Assets (16,944) 730
Change in Other Liabilities (2,018) 585
--------- ---------
Net Cash Flows From (Used For) Operating Activities (31,833) 18,569
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (25,154) (20,312)
Other - (127)
--------- ---------
Net Cash Flows Used For Investing Activities (25,154) (20,439)
--------- ---------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 69,991 13,375
Dividends Paid on Common Stock (13,498) (14,412)
Dividends Paid on Cumulative Preferred Stock (52) (52)
--------- ---------
Net Cash Flows From (Used For) Financing Activities 56,441 (1,089)
--------- ---------
Net Decrease in Cash and Cash Equivalents (546) (2,959)
Cash and Cash Equivalents at Beginning of Period 2,454 6,941
--------- ---------
Cash and Cash Equivalents at End of Period $ 1,908 $ 3,982
========= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $9,841,000 and
$10,139,000 and for income taxes was $2,408,000 and ($2,957,000) in 2002 and
2001, respectively.
See Notes to Financial Statements beginning on page L-1.
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 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. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, SWEPCo, WTU
5. Rate Matters AEP, APCo, CPL, PSO, SWEPCo, WTU
6. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
7. Financing and Related
Activities AEP, APCo, CPL, I&M, KPCo, OPCo, 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. In the
second quarter of 2002 we completed initial testing for goodwill
impairment of our UK and Australian retail electricity and supply
operations. As a result of that testing, we determined that we had a net
transitional impairment loss of $350 million, which is reported as a
cumulative effect of an accounting principle change.
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 six months
ended June 30, 2002 by operating segment are:
Energy
Wholesale Delivery Other AEP Consolidated
(in millions)
Balance January 1, 2002 $340 $37 $ 40 $417
Goodwill acquired 2 - - 2
Goodwill assigned from
purchase price allocation
for recent prior period
acquisitions 94 - - 94
Transitional impairment loss - - (27) (27)
Non-transitional
impairment loss - - (12) (12)
Foreign currency exchange
rate changes 6 - 2 8
---- --- ---- ----
Balance June 30, 2002 $442 $37 $ 3 $482
==== === ==== ====
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.
The transitional impairment loss related to SEEBOARD goodwill,
which is reported as a cumulative effect of an accounting change, is
excluded from the above schedule. Under SFAS 144, SEEBOARD's assets,
including goodwill, are reported as available for sale on one line in
the balance sheet. See Note 3 related to the sale of SEEBOARD and
CitiPower.
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 Six Months Ended June 30,
2002 2001
---- ----
(in millions)
Reported Net Income (Loss) $(107) $498
Add back: Goodwill amortization - 19
Add back amortization for intangibles with
indefinite lives under SFAS 142 - 4
----- ----
Adjusted Net Income (Loss) $(107) $521
===== ====
Earnings Per Share (Basic and Dilutive) Six Months Ended June 30,
2002 2001
---- ----
Reported Earnings (Loss) per Share $(0.33) $1.54
Add back: Goodwill amortization - 0.06
Add back amortization for intangibles with
indefinite lives under SFAS 142 - -
------ -----
Adjusted Earnings (Loss) per Share $(0.33) $1.60
====== =====
Acquired Intangible Assets
Acquired intangible assets subject to amortization are $42
million at June 30, 2002 and $53 million at December 31, 2001 net of
accumulated amortization. The gross carrying amount and accumulated
amortization by major asset class are:
June 30, 2002 December 31, 2001
Gross Carrying Accumulated Gross Carrying Accumulated
Amount Amortization Amount Amortization
(in millions) (in millions)
CitiPower retail
supply licenses $ - $- $24 $4
Dolet Hills advanced
Royalties 35 3 35 2
Unpatented Technology 10 - - -
--- -- --- --
Totals $45 $3 $59 $6
=== == === ==
Amortization of intangible assets was $2 million for the six
months ended June 30, 2002. Estimated aggregate amortization expense is
$4.5 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 $324 million and $421 million at June 30, 2002
and December 31, 2001. The reduction in the carrying values of the
CitiPower retail supply and distribution licenses since December 31,
2001 results from impairment charges recorded in the second quarter of
2002 and changes in the foreign currency exchange rate. See Note 3
related to the pending sale of CitiPower.
3. ACQUISITIONS AND DISPOSITIONS
Disposition of SEEBOARD
On June 18, 2002, AEP, through a wholly owned subsidiary,
entered into an agreement, subject to European Union ("EU") approval,
to sell its consolidated subsidiary SEEBOARD, a UK electricity supply
and distribution company. EU approval was received July 25, 2002 and
the sale was completed on July 29, 2002. AEP received approximately
$1.04 billion in cash from the sale, subject to a working capital true
up, and the buyer assumed SEEBOARD debt of approximately $1.12 billion,
resulting in a net impairment loss of $345 million using June 30, 2002
exchange rates. In accordance with SFAS 144 the results of operations
of SEEBOARD have been classified as discontinued operations in the
accompanying financial statements. $22 million of the net impairment
loss was recorded in the second quarter and is classified as
discontinued operations. The remaining $323 million of the net loss has
been classified as a transitional impairment loss from the adoption of
SFAS 142 (see Note 2) and has been reported as a cumulative effect of
an accounting change retroactive to January 1, 2002. Proceeds from the
sale of SEEBOARD were used to pay down bank facilities and short-term
debt.
The assets and liabilities of SEEBOARD have been aggregated on
the balance sheet as assets held for sale and liabilities held for
sale. The major classes of SEEBOARD's assets and liabilities held for
sale are:
June 30, 2002 December 31, 2001
(in millions)
Assets
Current Assets $ 324 $ 324
Plant, Property and Equipment, Net 1,457 1,283
Goodwill 867 1,129
Other Assets 102 96
------ ------
Total Assets Held For Sale $2,750 $2,832
====== ======
Liabilities
Current Liabilities $ 881 $ 752
Long-term Debt 739 701
Deferred Income Taxes 327 268
Other Liabilities 8 77
------ ------
Total Liabilities Held For Sale $1,955 $1,798
====== ======
Disposition of CitiPower
On July 19, 2002, AEP, through a wholly owned subsidiary
entered into an agreement to sell Citipower, a retail electricity and
gas supply and distribution subsidiary in Australia. AEP will receive
net cash of approximately $181 million and the buyer will assume
CitiPower debt of approximately $774 million. The transaction is
subject to a net asset true up and is anticipated to close in the third
quarter of 2002. AEP recorded a net impairment charge totaling $125
million. $98 million was recorded in the second quarter of 2002 and
relates to an impairment loss on the distribution license intangible
asset. The remaining $27 million of net impairment loss has been
classified as a transitional goodwill impairment loss from the adoption
of SFAS 142 (see Note 2) and has been recorded as a cumulative effect
of an accounting change retroactive to January 1, 2002.
Since the transaction occurred after the balance sheet date of
June 30, 2002, but before the issuance of the financial statements,
CitiPower's results of operation were not classified as discontinued
operation in accordance with SFAS 144. CitiPower's results of operation
will be reclassified as discontinued operations in the third quarter.
Also, CitiPower's assets and liabilities have not been aggregated on
the balance sheet as assets held for sale and liabilities held for
sale. This too will occur in the third quarter in accordance with SFAS
144.
Acquisition of European Trading
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. Results of operations are
included in AEP's 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.
REPs Transfer
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. 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. 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.
On June 27, 2002, the Ohio Consumers' Counsel, Industrial
Energy Users - Ohio and American Municipal Power - Ohio filed a
complaint with the PUCO alleging that CSPCo and OPCo have violated the
PUCO's orders regarding implementation of their transition plan and
violated other applicable law by failing to participate in an RTO.
The complainants seek, among other relief, an order from the
PUCO suspending collection of transition charges by CSPCo and OPCo until
transfer of control of their transmission assets has occurred and
imposing a $25,000 per company forfeiture for each day AEP fails to
comply with its commitment to transfer control of transmission assets to
an RTO.
Due to FERC delays in the approval of our RTO filings, CSPCo
and OPCo have been unable to implement their RTO participation plan.
Management is unable to predict the timing of FERC's final approval of
RTOs and the timing of an RTO being operational or the outcome of this
proceeding before the PUCO.
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. Pursuant to 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. However, the Virginia restructuring law allows
rates to be adjusted in certain circumstances including changes in fuel
prices (see Note 5). See the 2001 Annual Report for further discussion
of Virginia restructuring.
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 provisions 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.
Two unaffiliated Texas utilities reached settlement agreements
approved by the PUCT regarding recovery of stranded generation costs.
CPL is not presently engaged in any settlement discussions with the
PUCT. CPL's generation-related regulatory assets subject to recovery as
stranded costs are approximately $1.1 billion of which $949 million has
been securitized pending the 2004 true-up proceeding's determination of
stranded costs recovery including the recovery of stranded
generation-related regulatory assets. WTU and SWEPCo do not have any
recoverable Texas generation-related regulatory assets.
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. As discussed in Note 5 "Rate Matters", WTU filed its
final fuel reconciliation for its ERCOT service territory with the PUCT
in June 2002. 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 June 30, 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.
West Virginia Restructuring - Affecting AEP and APCo
As discussed in Note 7 of the 2001 Annual Report, the West
Virginia Legislature in 2000 approved an electricity restructuring plan.
Before implementation of the plan, the West Virginia Legislature needed
to enact legislation to preserve the revenues of state and local
government. In the past two legislative sessions, which usually end in
March each year, the West Virginia Legislature has not enacted the
required legislation. Due to the lack of activity, the Public Service
Commission of West Virginia closed two proceedings related to
electricity restructuring in the summer of 2002.
The two West Virginia Commission orders related to the
dismissal of the respective dockets intended originally to determine
whether West Virginia should deregulate the generation business, and to
develop the Commission's Deregulation Plan and related Commission rules
to implement the Plan.
Management is currently reviewing the impact of these two
orders to determine if the West Virginia Jurisdiction meets the
conditions to apply SFAS 71.
5. RATE MATTERS
Fuel Reconciliation - Affecting AEP and WTU
In June 2002 WTU filed with the PUCT to reconcile fuel costs
and to defer any unrecovered portion applicable to retail sales within its
ERCOT service area for inclusion in the 2004 true-up proceeding. This
reconciliation for the period of July 2000 through December 2001 will be
the final fuel reconciliation for WTU's ERCOT service territory. Texas
restructuring legislation eliminated fuel clause recovery mechanisms
beginning in 2002 for the ERCOT area and provides for a 2004 true-up
proceeding to determine recovery of final fuel balances. At December 31,
2001, the under-recovery balance associated with WTU's ERCOT service area
was $26.4 million including interest. WTU also requested authority to
surcharge its SPP customers. WTU's SPP customers will continue to be
subject to fuel reconciliations until competition begins. The
under-recovery balance at December 31, 2001 for WTU's service within SPP
was $0.7 million including interest. During the reconciliation period, WTU
incurred $292.7 million of eligible fuel and fuel related expenses serving
both ERCOT and SPP retail customers. The PUCT is not expected to act on
this issue prior to the end of 2002.
FERC Wholesale Fuel Complaint - Affecting AEP and WTU
As discussed in Note 5 of 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 plant 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
AEP subsidiaries which are the Texas retail electric providers (REP)
for the ERCOT area, CPL REP and WTU REP, filed with the PUCT in May 2002
to increase the fuel portion of their "price-to-beat" rate in compliance
with the Texas Restructuring Legislation and rules issued by the PUCT. 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. On July 15, 2002, the PUCT required
further hearings to reconsider the validity of their existing rules for
fuel factor adjustments. On July 24, 2002, CPL REP and WTU REP filed a
petition with the District Court seeking an injunction commanding the PUCT
to proceed to a final order based on the existing rules and prohibiting
the PUCT from conducting a remand proceeding. The District Court issued an
order on August 9, 2002 requiring the PUCT to comply with the existing
rules. CPL REP and WTU REP are unable to predict the response of the PUCT
to the Court's order and when or if they will be able to adjust the fuel
portion of their "price-to-beat" rates. A delay or denial of CPL REP's or
WTU REP's request to increase the fuel portion of their "price-to-beat"
rates could reduce AEP's future results of operations and cash flows.
FERC Transmission Rates - Affecting AEP, CPL, PSO, SWEPCo and WTU
In November 2001 FERC issued an order requiring CPL, PSO, SWEPCo and
WTU to submit revised open access transmission tariffs, and calculate and
issue refunds for overcharges from January 1, 1997. The order resulted
from a remand by an appeals court of a tariff compliance filing order
issued in November 1998 that had been appealed by certain customers. CPL
and WTU recorded refund provisions of $1.7 million and $0.7 million,
respectively, including interest in 2001 for this order. PSO and SWEPCo
recorded $100,000 each in 2001 for this order making the AEP total $2.6
million. On July 26, 2002, FERC approved a revised open access
transmission tariff. Refunds are to be completed within 30 days. The
amount of the refunds are being calculated. Management does not expect the
refunds to be materially different from the amounts provided in 2001.
Texas Transmission Cost Recovery - Affecting AEP, CPL and WTU
On July 15, 2002, CPL and WTU filed a petition to update their
Transmission Cost Recovery Factor (TCRF) as of September 1, 2002. The TCRF
allows for the pass through of changes in wholesale transmission costs
billed to the distribution service providers by transmission service
providers. CPL and WTU are seeking TCRF increases of $0.8 million and $0.2
million, respectively. The requested increases include amounts for an
interim increase granted by the PUCT for one unaffiliated transmission
service provider. The PUCT has not ruled on whether interim amounts
qualify for a TCRF. If the interim amount is disallowed, CPL's and WTU's
increase would be reduced to $0.4 million and $0.1 million, respectively.
Virginia Fuel Rate Filing - Affecting AEP and APCo
In July 2002 APCo filed with the Virginia SCC requesting an increase
in fuel rates effective January 1, 2003. The request would increase annual
revenues by approximately $28 million. A public hearing is scheduled for
September 23, 2002 related to this filing.
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, gas and coal.
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 six months ended June
30, 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
June 30, 2002 (in millions)
Revenues from:
External customers $26,002 $1,694 $ 246 $ - $27,942
Transactions with other operating segments (1,151) (5) (486) (1,642)
Segment EBIT 477 461 (174) 764
Total assets 35,544 13,190 2,424 51,158
June 30, 2001 Revenues from:
External customers 26,034 1,672 238 27,944
Transaction with other operating segments 1,067 10 30 (1,107) -
Segment EBIT 845 483 142 (71) 1,399
Total assets 29,566 14,379 7,539 (1,257) (a) 50,227
(a) Reconciling adjustment for Total Assets:
Eliminate intercompany balances (1,448)
Corporate assets 37
Other 154
-------
$(1,257)
=======
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.
Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001
Segment Segment
Revenues EBIT Total Assets Revenues EBIT Total Assets
Wholesale Segment (in thousands) (in thousands)
APCo $2,463,966 $111,292 $3,229,545 $3,523,410 $107,415 $3,666,392
CPL 591,805 67,406 3,047,642 973,148 133,446 2,935,249
CSPCo 1,636,821 116,606 2,249,185 2,015,358 119,544 2,499,506
I&M 1,870,602 7,886 3,649,646 2,394,505 86,108 3,994,291
KPCo 601,795 8,225 681,177 831,124 4,162 772,669
OPCo 2,394,324 192,718 3,473,145 3,061,833 125,565 3,927,606
PSO 378,279 5,684 872,625 644,622 12,124 859,240
SWEPCo 532,914 26,357 1,171,373 696,457 32,036 1,184,118
WTU 204,086 5,088 418,221 306,515 1,335 400,251
Segment Segment
Revenues EBIT Total Assets Revenues EBIT Total Assets
Energy Delivery Segment (in thousands) (in thousands)
APCo $294,470 $108,841 $2,547,817 $300,021 $115,711 $2,892,449
CPL 288,955 80,406 2,188,857 278,763 65,612 2,108,135
CSPCo 225,610 39,950 1,265,166 219,310 44,065 1,405,972
I&M 153,194 72,365 1,647,373 156,907 61,410 1,802,938
KPCo 66,514 29,053 659,723 67,164 27,246 748,333
OPCo 284,904 42,851 1,936,738 265,009 58,512 2,190,161
PSO 122,547 28,639 972,249 109,711 23,187 957,334
SWEPCo 152,943 39,635 1,219,185 164,027 51,909 1,232,449
WTU 79,179 12,313 556,654 81,330 21,041 532,734
Registrant Subsidiaries
Company Total Revenues EBIT Total Assets Revenues EBIT Total Assets
(in thousands) (in thousands)
APCo $2,758,436 $220,133 $5,777,362 $3,823,431 $223,126 $6,558,841
CPL 880,760 147,812 5,236,499 1,251,911 199,058 5,043,384
CSPCo 1,862,431 156,556 3,514,351 2,234,668 163,609 3,905,478
I&M 2,023,796 80,251 5,297,019 2,551,412 147,518 5,797,229
KPCo 668,309 37,278 1,340,900 898,288 31,408 1,521,002
OPCo 2,679,228 235,569 5,409,883 3,326,842 184,077 6,117,767
PSO 500,826 34,323 1,844,874 754,333 35,311 1,816,574
SWEPCo 685,857 65,992 2,390,558 860,484 83,945 2,416,567
WTU 283,265 17,401 974,875 387,845 22,376 932,985
7. FINANCING AND RELATED ACTIVITIES
Equity Units
In June 2002, AEP issued 6.9 million equity units at $50 per
unit ($345 million). Each equity-linked security consists of a forward
purchase contract and a senior note issued by AEP. The forward purchase
contracts obligate the holders to purchase from AEP shares of AEP common
stock on the stock purchase date of August 16, 2005. The purchase price
per equity unit is $50. The number of shares to be purchased under the
forward purchase contract will be determined under a formula based upon
the average closing price of AEP common stock near the stock purchase
date. The senior notes have a principal amount of $50 each and mature on
August 16, 2007. The senior notes are pledged as collateral to secure
the purchase of common stock under the forward purchase contracts.
Holders may satisfy their obligation under the forward purchase
contracts by allowing the senior notes to be remarketed. The proceeds
from the remarketing will be used to purchase a portfolio of U.S.
treasury securities that holders pledge to AEP to secure their
obligations under the forward purchase contracts. Alternatively, holders
may choose to continue holding the senior notes and use other resources
as consideration for the purchase of stock under the forward purchase
contracts.
AEP will make quarterly interest payments on the senior notes
at the initial annual rate of 5.75%. The interest rate can be reset
through a remarketing, which is initially scheduled for May 2005. AEP
will pay the purchaser contract adjustment payments at the annual rate
of 3.50% on the forward purchase contracts.
The present value of the contract adjustment payments has been
recorded as a liability in equity unit senior notes offset by a charge
to paid-in capital. Interest payments on the senior notes are reported
as interest expense and contract adjustment payments are charged against
the liability. Accretion of the contract adjustment payment liability is
reported as interest expense. We apply the treasury stock method to the
equity units to calculate diluted earnings per share.
Common Stock
In June 2002, AEP issued 16 million shares of common stock at
$40.90 per share through an equity offering and received net proceeds of
$634 million. Proceeds from the sale of equity units and common stock
were used to pay down short-term debt and establish a cash liquidity
reserve fund.
Issuances and Retirements of Long-term Debt
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 4). 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
Other issuances and retirements of long-term debt and other securities
during the first six months of 2002 were:
Type of Principal Interest
Company Debt Amount Rate Due Date
------- ------- --------- -------- --------
Issuances (in millions) (%)
---------
APCo Senior Unsecured Notes $ 450 4.80 2005
I&M Installment Purchase Contracts 50 4.90 2025
KPCo Senior Unsecured Notes 125 5.50 2007
SWEPCo Senior Unsecured Notes 200 4.50 2005
Non-Registrant
AEP Subs. Revolving Credit Agreement 143 Variable 2003
Retirements
CPL Senior Unsecured Notes $150 Variable 2002
I&M Installment Purchase Contract 50 Variable 2014
KPCo First Mortgage Bonds 15 7.90 2023
OPCo First Mortgage Bonds 5 8.80 2022
SWEPCo Senior Unsecured Notes 150 Variable 2002
Non-Registrant
AEP Subs. Notes Payable 12 Variable 2002-2007
Related Activities
AEP Credit renewed its sale of receivables agreement during the
second quarter of 2002. At June 30, 2002, the sale of receivables
agreement provided commitments of $600 million to purchase receivables
from AEP Credit, of which $455 million was outstanding. All of the
receivables sold, represented affiliate receivables. The commitment's
new term under the sale of receivables agreement will remain at $600
million until May 28, 2003. AEP Credit maintains a retained interest in
the receivables sold and this interest is pledged as collateral for the
collection of the receivables sold. The fair value of the retained
interest is based on book value due to the short-term nature of the
accounts receivables less an allowance for anticipated uncollectible
accounts.
In April 2002, AEP closed on a bridge loan facility consisting
of a $1,125 million 364-day revolving credit facility and a $600 million
364-day term loan facility to prepare for corporate separation. We
borrowed $600 million under the term loan facility and loaned the
amounts borrowed to CPL ($200 million), CSPCo ($250 million) and OPCo
($150 million). Pricing on the facilities and intercompany loans is
based on a spread over LIBOR.
AEP has available $3.5 billion in bank facilities
consisting of a $2.5 billion 364-day facility and a $1.0 billion
five-year facility maturing on May 31, 2005. On May 22, 2002, AEP
renewed the $2.5 billion facility for another year extending the
maturity date to May 21, 2003.
Upon the issuance of the $450 million 4.80% unsecured notes due
in 2005, APCo announced the following debt would be redeemed in July;
$75 million of 8.25% junior subordinated debentures due 2026, $90
million of 8% junior subordinated debentures due 2027, $40 million of
6.65% first mortgage bonds due 2003 and $30 million of 6.85% first
mortgage bonds due 2003.
Upon issuance of the $125 million 5.50% unsecured notes due
2007, KPCo announced the redemption of $45 million of first mortgage
bonds on August 1.
In preparation for corporate restructuring, management
announced the following bonds would be redeemed in July, CSPCo's $72.8
million remaining outstanding principal amount of the 8-3/8% junior
subordinated debentures due 2025 and $40 million of the 7.92% junior
subordinated debentures due 2027 and OPCo's $85 million remaining
outstanding principal of the 8.16% junior subordinated debentures due
2025 and $50 million of the 7.92% junior subordinated debentures due
2027.
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 which could have resulted in the imposition of 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. Most of those states have submitted
conforming compliance plans and the appeal filed by AEP subsidiaries and
other utilities in the D.C. Circuit Court to review this ruling has been
dismissed.
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 imposed 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 responded 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 in May
2002 advising that no changes in the growth factors used to set the NOx
budgets were warranted. In June 2002 AEP subsidiaries joined other
utilities and industrial organizations in seeking a review of Federal
EPA's action in the D.C. Circuit Court.
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 June 30, 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 160
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 purportedly owned the cushion gas
had entered into a financing arrangement with a group of banks. These
banks purported to have certain rights to the cushion gas in certain
events of default. We have been informed by the banks of Bammel Trust's
default under the terms of their financing agreement. The banks filed a
lawsuit against HPL seeking a declaratory judgment that they have a
valid and enforceable security interest in this cushion gas which would
permit them to cause the withdrawal of this gas from the storage
facility. Management is unable to predict the outcome of this lawsuit or
its impact on results of operation and cash flows.
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 the lawsuit related to the cushion gas
financing agreement, our future results of operations, cash flows and
possibly financial condition could be adversely impacted.
Energy Market Investigations - Affecting AEP
In February 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 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 required 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 complied with the
order and denied our involvement with those trading practices.
On May 21, 2002, the FERC issued a further data request with
respect to this matter to us and over 100 other market participants
requesting information for the years 2000 and 2001 concerning "wash",
"round trip" or "sale/buy back" trading in the Western System
Coordinating Council (WSCC), which involves the sale of an electricity
product to another company together with a simultaneous purchase of the
same product at the same price (collectively, "wash sales"). Similarly,
on May 22, 2002, the FERC issued an additional data request with respect
to this matter to us and other market participants requesting similar
information for the same period with respect to the sale of natural gas
products in the WSCC and Texas. After reviewing our records, we
responded to the FERC that we did not participate in any "wash sale"
transactions involving power or gas in the relevant market. We further
informed the FERC that certain of our traders did engage in trades on
the Intercontinental Exchange, an electronic electricity trading
platform owned by a group of electricity trading companies, including
us, on September 21, 2001, the day on which all brokerage commissions
for trades on that exchange were donated to charities for the victims of
the September 11, 2001 terrorist attacks, which do not meet the FERC
criteria for a "wash sale" but do have certain characteristics in common
with such sales. In response to a request from the California attorney
general for a copy of AEP's responses to the FERC inquires, we provided
the pertinent information.
The PUCT also issued similar data requests to AEP and other power
marketers. AEP responded to such data request by the July 2, 2002
response date. The US Commodity Futures Trading Commission (CFTC) issued
a subpoena to us on June 17, 2002 requesting information with respect to
"wash sale" trading practices. We responded to CFTC. In addition, the US
Department of Justice made a civil investigation demand to us and other
electric generating companies concerning their investigation of the
Intercontinental Exchange. We have recently completed a review of our
trading activities in the United States for the last three years
involving sequential trades with the same terms and counterparties. The
revenue from such trading is not material to our financial statements.
We believe that substantially all these transactions involve economic
substance and risk transference and do not constitute "wash sales".
FERC Proposed Security Standards
In July 2002 the FERC published for comment its proposed security
standards as part of the Standards for Market Design (SMD). These
standards are intended to ensure all market participants have a basic
security program that effectively protects the electric grid and
related market activities and require compliance by January 1, 2004.
The impact of these proposed standards is far-reaching and has
significant penalties for non-compliance. These standards apply to
marketers, transmission owners, and power producers. For the AEP System
this includes: regulated and non-regulated power generation plants,
transmission systems, distribution systems, regulated and non-regulated
energy trading, and related areas of business. These standards
represent a significant effort that will impact the entire AEP System.
Unless the cost can be recovered from customers, results of operations
and cash flows would be adversely affected.
FERC Market Power Mitigation
A FERC order on AEP's triennial market based wholesale power rate
authorization update required certain mitigation actions that AEP would
need to take for sales/purchases within its control area and required
AEP to post information on its website regarding its power systems
status. As a result of a request for rehearing filed by AEP and other
market participants, FERC issued an order delaying the effective date of
the mitigation plan until after a planned technical conference on market
power determination. No such conference has been held and management is
unable to predict the timing of any further action by the FERC or its
affect on future results of operations and cash flows.
Minority Interest in Finance Subsidiary - Affecting AEP
In August 2001, AEP formed Caddis Partners, LLC (Caddis), a
consolidated subsidiary, and sold a non-controlling preferred member
interest in Caddis to an unconsolidated special purpose entity
(Steelhead) for $750 million. Under the provisions of the Caddis
formation agreements, the preferred member interest receives quarterly a
preferred return equal to an adjusted floating reference rate. The $750
million received replaced interim funding used to acquire Houston Pipe
Line Company in June 2001.
The preferred interest is supported by natural gas pipeline
assets and $321.4 million of preferred stock issued by an AEP subsidiary
to the AEP affiliate which has the managing member interest in Caddis.
Such preferred stock is convertible into AEP common stock upon the
occurrence of certain events including AEP's stock price closing below
$18.75 for ten consecutive trading days. AEP can elect not to have the
transaction supported by such preferred stock if the preferred interest
were reduced by $225 million. In addition, Caddis has the right to
redeem the preferred member interest at any time.
The initial period of the preferred interest is through August
2006. At the end of the initial period, Caddis will either reset the
preferred rate, re-market the preferred member interests to new
investors, redeem the preferred member interests, in whole or in part
including accrued return, or liquidate in accordance with the provisions
of applicable agreements.
Steelhead has the right to terminate the transaction and
liquidate Caddis upon the occurrence of certain events including a
default in the payment of the preferred return. Steelhead's rights
include: forcing a liquidation of Caddis and acting as the liquidator,
and requiring the conversion of the $321.4 million of AEP subsidiary
preferred stock into AEP common stock. If the preferred member interest
exercised its rights to liquidate under these conditions, then AEP would
evaluate whether to refinance at that time or relinquish the assets that
support the preferred member interest. Liquidation of the preferred
interest or of Caddis could negatively impact AEP's liquidity.
Caddis and the AEP subsidiary which acts as its managing member
are each a limited liability company, with a separate existence and
identity from its members, and the assets of each are separate and
legally distinct from AEP. The results of operations, cash flows and
financial position of Caddis and such managing member are consolidated
with AEP for financial reporting purposes. The preferred member interest
and payments of the preferred return are reported on AEP's income
statement and balance sheet as Minority Interest in Finance Subsidiary.
Foreign Distribution Projects - Affecting AEP
We own a 44% equity interest in Vale, a Brazilian electric
operating company which was purchased for a total of $149 million. On
December 1, 2001 we converted a $66 million note receivable and accrued
interest into a 20% equity interest in Caiua (Brazilian electric
operating company), a subsidiary of Vale. Vale and Caiua have
experienced losses from operations and our investment has been affected
by the devaluation of the Brazilian Real. The cumulative equity share of
operating and foreign currency translation losses through June 30, 2002
is approximately $47 million and $58 million, respectively, net of tax.
The cumulative equity share of operating and foreign currency
translation losses through December 31, 2001 is approximately $46
million and $54 million, respectively, net of tax. Both investments are
covered by a put option, which, if exercised, requires our partners in
Vale to purchase our Vale and Caiua shares at a minimum price equal to
the U.S. dollar equivalent of the original purchase price. As a result,
management has concluded that the investment carrying amount should not
be reduced below the put option value unless it is deemed to be an other
than temporary impairment and our partners in Vale are deemed unable to
fulfill their responsibilities under the put option. In January 2002,
management evaluated through an independent third-party, the ability of
its Vale partners to fulfill their responsibilities under the put option
agreement and concluded that our partners should be able to fulfill
their responsibilities.
Management believes that the decline in the value of its
investment in Vale in US dollars is not other than temporary. As a
result and pursuant to the put option agreement, these losses have not
been applied to reduce the carrying values of the Vale and Caiua
investments. As a result we will not recognize any future earnings from
Vale and Caiua until the operating losses are recovered. In addition,
our partners have a principal payment due in November 2002 in the amount
of $55 million. Our partners plan to refinance the debt before the
payment comes due. Should the impairment of our investment become other
than temporary due to our partners in Vale becoming unable to fulfill
their responsibilities, it would have an adverse effect on future
results of operations.
Management will continue to monitor both the status of the losses
and its partners ability to fulfill their obligations under the put
option.
Investments in Telecommunications Companies - Affecting AEP
AEP provides telecommunications services to business and
telecommunication companies through a broadband fiber optic network. AEP
conducts its operations through an ownership interest in a joint
venture, AFN Networks, LLC (AFN), and through its AEP Communications and
C3 subsidiaries.
Management is currently reassessing its telecommunications
business strategy and considering certain changes that could include
additional investment in AFN, possible financial control of the joint
venture's operations, and a reorganization of its other
telecommunications operations in order to optimize the value of such
assets. The review of the telecommunications business strategy is
expected to be completed in the third quarter of 2002. In connection
with the completion of this assessment and reorganization activities,
management will review its investment in telecommunication companies for
any impairment of value. Management is unable to determine whether there
is any impairment until such evaluation is complete. At June 30, 2002
AEP's investment in telecommunications companies was approximately $252
million.
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 and
year-to-date period ended June 30, 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. In April 2002
Moody's Investors Service placed AEP and five of its registrant subsidiaries
(CPL, CSPCo, OPCo, SWEPCo and WTU) on credit rating watch for possible
downgrade. The review of SWEPCo could conclude with more than a one notch
downgrade. Moody's confirmed the credit ratings of four of AEP registrant
subsidiaries (APCo, I&M, KPCo, and PSO). In May 2002, Standard & Poors confirmed
AEP and its registrant subsidiaries senior unsecured debt rating. First Mortgage
Bond ratings of all the registrant subsidiaries were lowered to "BBB+" from "A".
AEP's commercial paper programs short-term ratings of A2 and P2 were confirmed
by Moody's and Standard and Poor's, respectively.
The review of the companies' debt position and credit rating is being
completed in anticipation of corporate separation. We are working with the
rating agencies 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.
At June 30, 2002, the ratings of AEP's subsidiaries' first mortgage
bonds are listed in the following table:
Company Moody's S&P Fitch
APCo A3 BBB+ A-
CPL A3 BBB+ A
CSPCo A3 BBB+ A
I&M Baa1 BBB+ BBB+
KPCo Baa1 BBB+ BBB+
OPCo A3 BBB+ A-
PSO A1 BBB+ A+
SWEPCo A1 BBB+ A
WTU A2 BBB+ A
The ratings at June 30, 2002 for senior unsecured debt are listed in
the following table:
Company Moody's S&P Fitch
aEP Baa1 BBB+ BBB+
AEP Resources* Baa1 BBB+ BBB+
APCo Baa1 BBB+ BBB+
CPL Baa1 BBB+ BBB+
CSPCo A3 BBB+ A-
I&M Baa2 BBB+ BBB
KPCo Baa2 BBB+ BBB
OPCo A3 BBB+ BBB+
PSO A2 BBB+ A
SWEPCo A2 BBB+ A-
WTU - BBB+ -
*The rating is for a series of senior notes issued with a
Support Agreement from AEP.
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,
convertible securities, 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
come from the parent company's commercial paper program and are loaned to
subsidiaries through inter-company notes. The commercial paper program is backed
by $3.5 billion in bank facilities of which $1 billion matures in May 2005 and
$2.5 billion matures in May 2003. At June 30, 2002, approximately $1.4 billion
was outstanding in commercial paper. In addition, AEP has a $1.725 billion bank
facility maturing in April 2003 that is available for debt refinancing in
anticipation of corporate separation. At June 30, 2002, $600 million was
outstanding under that facility. We anticipate repayment of the facility through
the issuance of bonds by certain subsidiaries. The pricing on the facility is
based on a spread over LIBOR.
During the first half of 2002 cash flow from operations was $96 million,
including $107 million from a net loss and $912 million from depreciation,
amortization and deferred taxes. Capital expenditures including acquisitions
were $785 million and dividends on common stock were $387 million. Cash from
operations and the issuance of common stock, common equity units and transition
funding bonds provided funds to 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 third quarter of
2002. Long-term funding arrangements are often complex and take time to
complete.
In anticipation of corporate separation, CPL and WTU both initiated
tenders for their first mortgage bonds in July. The cumulative amounts tendered
for CPL and WTU was $401 million and $89 million, respectively. In order to pay
for a portion of these retired bonds, as well as previously retired bonds, AEP
borrowed $600 million under the term loan facility. In turn, AEP loaned the
amounts it borrowed to CPL ($200 million), CSPCo ($250 million) and OPCo ($150
million).
In June 2002 we issued 16 million shares of AEP common stock and 6.9
million equity units. We used the proceeds from the issuances of $968 million to
establish a $300 million cash liquidity reserve and to reduce debt. The cash
reserve enhances our liquidity and is included in cash and cash equivalents on
AEP's consolidated balance sheet.
Total consolidated plant and property additions including capital leases
for the six months ended June 30, 2002 were $865 million. The following table
shows the plant and property additions by certain registrant subsidiaries:
Company Amount
------- ------
(in millions)
APCo $129
CPL 65
I&M 69
OPCo 158
SWEPCo 36
Pending and 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 July 2002 we completed the sale of SEEBOARD, an energy delivery and
power supply business in the UK, receiving cash of approximately $1.04 billion
which will be used to reduce debt. The sale resulted in a loss of $345 million
(See Note 3).
We have 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.
In July 2002 we reached an agreement to sell CitiPower, our energy
delivery and retail supply businesses in Australia. It is anticipated that AEP
will receive approximately $180 million in cash and the sale will result in a
$125 million loss (See Note 3).
AEP provides telecommunications services to business and
telecommunication companies through a broadband fiber optic network. AEP
conducts its operations through an ownership interest in a joint venture, AFN
Networks, LLC (AFN), and through its AEP Communications and C3 subsidiaries.
Management is currently reassessing its telecommunications business
strategy and considering certain changes that could include additional
investment in AFN, possible financial control of the joint venture's operations,
and a reorganization of its other telecommunications operations in order to
optimize the value of such assets. The review of the telecommunications business
strategy is expected to be completed in the third quarter of 2002. In connection
with the completion of this assessment and reorganization activities, management
will review its investment in telecommunication companies for any impairment of
value. Management is unable to determine whether there is any impairment until
such evaluation is complete. At June 30, 2002 AEP's investment in
telecommunications companies was approximately $252 million.
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 six state regulatory commissions and other major 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
RTOs. 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
competitive, reliable electric service and rejected the Alliance RTO's filing.
In May 2002 AEP announced an agreement with the PJM Interconnection to pursue
terms for certain subsidiares to participate in its RTO. Final agreements are
expected to be negotiated. In July 2002 the FERC tentatively approved certain
AEP subsidiaries' decision to join PJM subject to certain conditions being met.
The performance of these conditions are only partially under AEP's control.
In other RTO developments FERC recently accepted conditionally, filings
related to a proposed consolidation of the Midwest Independent System Operator
(MISO) and the SPP. In that order the FERC required the AEP subsidiaries in
SPP to file reasons why those subsidiaries should not be required to join MISO.
AEP filed with the FERC a response that additional analysis was required prior
to AEP making an RTO decision. The SPP companies are also regulated by state
public utility commissions, and the Louisiana and Arkansas commissions also
filed responses to the FERC's RTO order indicating that additional analysis was
required.
Management is unable to predict the final 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 4 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 the Texas
jurisdiction competition began in the ERCOT area but was delayed in the SPP
area. In Ohio, Michigan and Virginia virtually all customers continue to receive
electric generation, transmission and distribution services from our electric
operating companies.
On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users
- - Ohio and American Municipal Power - Ohio filed a complaint with the PUCO
alleging that CSPCo and OPCo have violated the PUCO's orders regarding
implementation of their transition plan and violated other applicable law by
failing to participate in an RTO.
The complainants seek, among other relief, an order from the PUCO
suspending collection of transition charges by CSPCo and OPCo until transfer of
control of their transmission assets has occurred and imposing a $25,000 per
company forfeiture for each day AEP fails to comply with its commitment to
transfer control of transmission assets to an RTO.
Due to FERC delays in the approval of our RTO filings, CSPCo and OPCo
have been unable to implement their RTO plan. Management is unable to predict
the timing of FERC's final approval of RTOs and the timing of an RTO being
operational or the outcome of this proceeding before the PUCO.
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 for CPL and WTU in ERCOT 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.
Two unaffiliated Texas utilities reached settlement agreements approved
by the PUCT regarding recovery of stranded generation costs. CPL is not
presently engaged in any settlement discussions with the PUCT. Under the Texas
Legislation, a 2004 true-up proceeding will determine recovery of stranded costs
including final fuel recovery balances, net regulatory assets, certain
environmental costs, accumulated excess earnings and other issues. CPL's
generation-related regulatory assets subject to recovery as stranded costs are
approximately $1.1 billion of which $949 million has been securitized pending
the 2004 true-up proceeding's determination of stranded costs recovery including
the recovery of stranded generation-related regulatory assets. WTU and SWEPCo do
not have any recoverable Texas generation-related regulatory assets.
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 which could have resulted
in the imposition of 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. Most of those states
have submitted conforming compliance plans and the appeal filed by AEP
subsidiaries and other utilities in the D.C. Circuit Court to review this ruling
has been dismissed.
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
in May 2002 advising that no changes in the growth factors used to set the NOx
budgets were warranted. In June 2002 AEP subsidiaries joined other utilities and
industrial organizations in seeking a review of Federal EPA's action in the D.C.
Circuit Court.
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 June 30, 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 purportedly owned the
cushion gas had entered into a financing arrangement with a group of banks. The
banks purported to have certain rights to the cushion gas in certain events of
default. We have been informed by the banks of Bammel Trust's default under the
terms of their financing agreement. The banks filed a lawsuit against HPL
seeking a declaratory judgment that they have a valid and enforceable security
interest in this cushion gas which would permit them to cause the withdrawal of
this gas from the storage facility. Management is unable to predict the outcome
of this lawsuit or its impact on results of operation and cash flows.
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 the lawsuit related to the cushion gas financing agreement, our
future results of operations, cash flows and possibly financial condition could
be adversely impacted.
Energy Market Investigations - Affecting AEP
In February 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 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 required 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 complied with the order and denied our involvement with those trading
practices.
On May 21, 2002, the FERC issued a further data request with respect to
this matter to us and over 100 other market participants requesting information
for the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back"
trading in the Western System Coordinating Council (WSCC), which involves the
sale of an electricity product to another company together with a simultaneous
purchase of the same product at the same price (collectively, "wash sales").
Similarly, on May 22, 2002, the FERC issued an additional data request with
respect to this matter to us and other market participants requesting similar
information for the same period with respect to the sale of natural gas products
in the WSCC and Texas. After reviewing our records, we responded to the FERC
that we did not participate in any "wash sale" transactions involving power or
gas in the relevant market. We further informed the FERC that certain of our
traders did engage in trades on the Intercontinental Exchange, an electronic
electricity trading platform owned by a group of electricity trading companies,
including us, on September 21, 2001, the day on which all brokerage commissions
for trades on that exchange were donated to charities for the victims of the
September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a
"wash sale" but do have certain characteristics in common with such sales. In
response to a request from the California attorney general for a copy of AEP's
responses to the FERC inquires, we provided the pertinent information.
The PUCT also issued similar data requests to AEP and other power
marketers. AEP responded to such data request by the July 2, 2002 response date.
The US Commodity Futures Trading Commission (CFTC) issued a subpoena on June 17,
2002 requesting information with respect to "wash sale" trading practices. We
responded to CFTC. In addition, the US Department of Justice made a civil
investigation demand to us and other electric generating companies concerning
their investigation of the Intercontinental Exchange. We have recently completed
a review of our trading activities in the United States for the last three years
involving sequential trades with the same terms and counterparties. The revenue
from such trading is not material to our financial statements. We believe that
substantially all these transactions involve economic substance and risk
transference and do not constitute "wash sales".
Minority Interest in Finance Subsidiary - Affecting AEP
In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated
subsidiary, and sold a non-controlling preferred member interest in Caddis to an
unconsolidated special purpose entity (Steelhead) for $750 million. Under the
provisions of the Caddis formation agreements, the preferred member interest
receives quarterly a preferred return equal to an adjusted floating reference
rate. The $750 million received replaced interim funding used to acquire Houston
Pipe Line Company in June 2001.
The preferred interest is supported by natural gas pipeline assets and
$321.4 million of preferred stock issued by an AEP subsidiary to the AEP
affiliate which has the managing member interest in Caddis. Such preferred stock
is convertible into AEP common stock upon the occurrence of certain events
including AEP's stock price closing below $18.75 for ten consecutive trading
days. AEP can elect not to have the transaction supported by such preferred
stock if the preferred interest were reduced by $225 million. In addition,
Caddis has the right to redeem the preferred member interest at any time.
The initial period of the preferred interest is through August 2006. At
the end of the initial period, Caddis will either reset the preferred rate,
re-market the preferred member interests to new investors, redeem the preferred
member interests, in whole or in part including accrued return, or liquidate in
accordance with the provisions of applicable agreements.
Steelhead has the right to terminate the transaction and liquidate
Caddis upon the occurrence of certain events including a default in the payment
of the preferred return. Steelhead's rights include: forcing a liquidation of
Caddis and acting as the liquidator, and requiring the conversion of the $321.4
million of AEP subsidiary preferred stock into AEP common stock. If the
preferred member interest exercised its rights to liquidate under these
conditions, then AEP would evaluate whether to refinance at that time or
relinquish the assets that support the preferred member interest. Liquidation of
the preferred interest or of Caddis could negatively impact AEP's liquidity.
Foreign Distribution Projects - Affecting AEP
We own a 44% equity interest in Vale, a Brazilian electric operating
company which was purchased for a total of $149 million. On December 1, 2001 we
converted a $66 million note receivable and accrued interest into a 20% equity
interest in Caiua (Brazilian electric operating company), a subsidiary of Vale.
Vale and Caiua have experienced losses from operations and our investment has
been affected by the devaluation of the Brazilian Real. The cumulative equity
share of operating and foreign currency translation losses through June 30, 2002
is approximately $47 million and $58 million, respectively, net of tax. The
cumulative equity share of operating and foreign currency translation losses
through December 31, 2001 is approximately $46 million and $54 million,
respectively, net of tax. Both investments are covered by a put option, which,
if exercised, requires our partners in Vale to purchase our Vale and Caiua
shares at a minimum price equal to the U.S. dollar equivalent of the original
purchase price. As a result, management has concluded that the investment
carrying amount should not be reduced below the put option value unless it is
deemed to be an other than temporary impairment and our partners in Vale are
deemed unable to fulfill their responsibilities under the put option. In January
2002, management evaluated through an independent third-party, the ability of
its Vale partners to fulfill their responsibilities under the put option
agreement and concluded that our partners should be able to fulfill their
responsibilities.
Management believes that the decline in the value of its investment in
Vale in US dollars is not other than temporary. As a result and pursuant to the
put option agreement, these losses have not been applied to reduce the carrying
values of the Vale and Caiua investments. As a result we will not recognize any
future earnings from Vale and Caiua until the operating losses are recovered. In
addition, our partners have a principal payment due in November 2002 in the
amount of $55 million. Our partners plan to refinance the debt before the
payment comes due. Should the impairment of our investment become other than
temporary due to our partners in Vale becoming unable to fulfill their
responsibilities, it would have an adverse effect on future results of
operations.
Management will continue to monitor both the status of the losses and
its partners ability to fulfill their obligations under the put option.
FERC Proposed Security Standards
In July 2002 the FERC published for comment its proposed security
standards as part of the Standards for Market Design (SMD). These standards are
intended to ensure all market participants have a basic security program that
effectively protects the electric grid and related market activities and
require compliance by January 1, 2004. The impact of these proposed standards
is far-reaching and has significant penalties for non-compliance. These
standards apply to marketers, transmission owners, and power producers. For
the AEP System this includes: regulated and non-regulated power generation
plants, transmission systems, distribution systems, regulated and
non-regulated energy trading, and related areas of business. These standards
represent a significant effort that will impact the entire AEP System. Unless
the cost can be recovered from customers, results of operations and cash flows
would be adversely affected.
FERC Market Power Mitigation
A FERC order on AEP's triennial market based wholesale power rate
authorization update required certain mitigation actions that AEP would need to
take for sales/purchases within its control area and required AEP to post
information on its website regarding its power systems status. As a result of a
request for rehearing filed by AEP and other market participants, FERC issued an
order delaying the effective date of the mitigation plan until after a planned
technical conference on market power determination. No such conference has been
held and management is unable to predict the timing of any further action by the
FERC or its affect on future results of operations and cash flows.
Other
AEP and its subsidiary registrants continue to be involved in certain
other matters discussed in the 2001 Annual Report.
New Accounting Standard
In June 2002, the FASB's Emerging Issues Task Force (EITF) in Issue No.
02-3 "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities", reached a consensus that energy trading contracts (whether realized
or unrealized and whether financially or physically settled) should be shown net
in the income statement and that expanded disclosures of energy trading
activities are required. This consensus is effective for periods ending after
July 15, 2002 and reclassification of prior period amounts is required. Our
adoption of EITF Issue No. 02-3 in the third quarter 2002 financial statements
will lead to a material decrease in both revenues and purchased energy expense.
There will be no impact on results of operations. Previous guidance in EITF
Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities", permitted settled forward energy trading contract sales
and purchases to be shown either gross or net in the income statement. AEP
currently records, and reports upon settlement, sales under forward trading
contracts as revenues and purchases under forward trading contracts as purchased
energy expense.
The table below shows the amounts of revenues and purchased energy
expense that AEP would report if forward sales and purchase contracts that
settle financially were accounted for on a net basis. The determination of net
trading revenues under EITF Issue No. 02-3 may yield a different result than
calculating net revenues on the basis of financially settled transactions only.
We are currently assessing the application of EITF Issue No. 02-3 to report
trading transactions on a net basis.
Six Months Ended June 30,
2002 2001
(in millions)
Gross Net Gross Net
----- --- ----- ---
Revenues:
Electricity Marketing and Trading $ 17,525 $4,042 $18,831 $4,788
Gas Marketing and Trading 8,477 1,014 7,203 573
Domestic Electricity Delivery 1,694 1,694 1,672 1,672
Other Investments 246 246 238 238
------- ------ ------- ------
Total $27,942 $6,996 $27,944 $7,271
======= ====== ======= ======
Gross Net Gross Net
----- --- ----- ---
Fuel and Purchased Energy Expense:
Electricity Marketing and Trading $ 15,046 $1,563 $16,945 $2,902
Gas Marketing and Trading 8,602 1,139 6,939 309
Other Investments 165 165 104 104
------- ------ ------- ------
Total $23,813 $2,867 $23,988 $3,315
======= ====== ======= ======
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 June 30, 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 for the:
Six Months Ended Year Ended
June 30, December 31,
2002 2001
---- ----
High Average Low High Average Low
(in millions) (in millions)
AEP $22 $12 $6 $28 $14 $5
APCo 3 2 1 4 1 -
CPL - - - 3 1 -
CSPCo 2 1 - 2 1 -
I&M 2 1 - 3 1 -
KPCo 1 - - 1 - -
OPCo 3 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 $639 million at June
30, 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 certain
power trading transactions and certain 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 June 30, 2002. At June 30, 2002 approximately 8% 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:
June 30, 2002
(in millions)
AAA/Exchanges $ - $51 $ 51
AA 115 - 115
A 327 - 327
BBB 784 7 791
Below Investment
Grade 103 2 105
------ --- ------
Total $1,329 $60 $1,389
====== === ======
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 June 30, 2002 and December 31,
2001 were $241 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 second quarter of 2002 resulted in an
unrealized increase in revenues of $40 million and unrealized increase in
revenues of $87 million year-to-date. 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).
Six Months Ended
June 30,
2002
(in millions)
Revenues (including mark-to-market adjustment) $27,942
Fuel and Purchased Energy Expense 23,813
-------
Net Revenues $ 4,129
=======
Mark-to-Market Revenues on Open Trading Positions $87*
===
Percentage of Net Revenues Represented by
Mark-to-Market on Open Trading Positions 2%
=
*Excludes reversal of $294 million of mark to market for contracts that settled
in 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 June
30, 2002 of $187 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
June 30, December 31,
--------------- ------------
2002 2001
---- ----
(in millions) (in millions)
Energy Trading and Derivative Contracts:
Current Asset $ 9,466 $ 8,572
Long-term Asset 3,672 2,370
Current Liability (9,538) (8,311)
Long-term Liability (3,444) (2,183)
------- -------
Net Fair Value of Energy Trading Contracts and
Derivative Contracts 156 448
Less non-trading related derivatives (31) -
------- -------
Net Fair Value of Energy Trading Contracts and
Related Derivatives $ 187 $ 448
======= =======
The above net fair value of energy trading contracts and related derivatives
includes $47 million, at June 30, 2002, in unrealized mark-to-market gains that
are recognized in the income statement at June 30, 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 (367) (a)
Adjustments to (gain) Loss for Contracts entered into and
Settled during period 108 (a)
Fair Value of new open contracts when entered into during the period 50 (b)
Net option premium payments 21
Change In fair value due to Methodology Changes 1 (c)
Changes in market value of contracts (74) (d)
-----
Net Fair Value of Energy Trading Contracts and Commodity Derivatives
at June 30, 2002 $ 187 (e)
=====
(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 $367 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) The Company changed the discount rate applied to its trading portfolio
from BBB+ Utility to LIBOR in the second quarter which increased fair
value by $10 million. In addition, the Company changed its methodology
in valuing a spread option model so as to more accurately reflect the
exercising of power transactions at optimal prices which reduced fair
value by $9 million.
(d) "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.
(e) The net change in the fair value of energy trading contracts for 2002
that resulted in a decrease of $261 million ($187 million less $448
million) represents the balance sheet change. The net
mark-to-market gain on energy trading contracts of $47 million and net
mark-to-market gain on gas inventory positions of $40 million
represent the impact on earnings related to open trading positions
as of June 30, 2002. The difference is related primarily to settlement
of prior period open energy trading contracts ($294 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 (19,026) (1,133) (12,470)
Change in Fair Value Due To
Methodology Changes 350 42 228
Adjustments to (gain) loss for
Contracts entered into and settled
during the period 7,419 761 4,848
Fair Value of new open Contracts
when entered into during period 9,031 1,897 5,901
Net option premium payments 354 - 232
Changes in market value of Contracts 14,669 (5,498) 12,522
-------- ------- --------
Net Fair Value of Energy Trading
Contracts at June 30, 2002 $ 88,498 $ (74) $ 59,710
======== ======= ========
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 (13,492) (4,921) (16,959)
Change in Fair Value Due To
Methodology Changes 247 90 311
Adjustments to (gain) loss for
Contracts entered into and settled
During the period 5,246 1,915 6,593
Fair Value of new open Contracts
when entered into during period 6,385 2,331 8,025
Net option premium payments 251 92 315
Changes in market value of Contracts (1,014) 4,972 26,175
------- ------- --------
Net Fair Value of Energy Trading
Contracts at June 30, 2002 $ 58,968 $17,208 $ 89,906
======== ======= ========
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 (863) (990) (336)
Change in Fair Value Due To
Methodology Changes 32 36 12
Adjustments to (gain) loss for
Contracts Entered into and settled
during period 579 665 226
Fair Value of new open Contracts
when entered into during period 605 694 2,246
Net option premium payments - - -
Changes in market value of Contracts (7,178) (8,239) (1,013)
------- ------- -------
Net Fair Value of Energy Trading
Contracts at June 30, 2002 $(4,391) $(4,934) $ 2,050
======= ======= =======
Energy Trading Contract Maturities
Fair Value of Contracts at June 30, 2002
Maturities
(in millions)
Total
AEP Consolidated Less than 4-5 In Excess Fair
Source of Fair Value 1 year 1-3 years years Of 5 years Value
- -------------------- ------ --------- ----- ---------- -----
Prices actively quoted (a) $(134) $ 84 $ - $ - $(50)
Prices provided by other external
Sources (b) 74 115 8 - 197
Prices based on models and other
Valuation methods (c) (2) (26) 40 28 40
----- ---- --- --- ----
Total $ (62) $173 $48 $28 $187
===== ==== === === ====
Energy Trading Contract Maturities
Fair Value of Contracts at June 30, 2002
Maturities
(in thousands)
Total
Less than 4-5 In Excess Fair
Source of Fair Value 1 year 1-3 years years Of 5 years Value
- -------------------- ------ --------- ----- ---------- -----
APCo
Prices provided by other
External Sources (b) $23,532 $14,422 $ 2,358 $ - $40,312
Prices based on models and other
Valuation methods (c) 6,079 23,757 9,655 8,695 48,186
------- ------- ------- ------ -------
Total $29,611 $38,179 $12,013 $8,695 $88,498
======= ======= ======= ====== =======
CPL
Prices provided by other
External Sources (b) $(2,458) $ 739 $121 $ - $(1,598)
Prices based on models and other
Valuation methods (c) (635) 1,218 495 446 1,524
-------- ------ ---- ---- -------
Total $(3,093) $1,957 $616 $446 $ (74)
======== ====== ==== ==== =======
CSP
Prices provided by other
External Sources (b) $16,874 $ 9,423 $1,540 $ - $27,837
Prices based on models and other
Valuation methods (c) 4,359 15,523 6,309 5,682 31,873
------- ------- ------ ------ -------
Total $21,233 $24,946 $7,849 $5,682 $59,710
======= ======= ====== ====== =======
KPCo
Prices provided by other
External Sources (b) $1,599 $3,722 $ 608 $ - $ 5,929
Prices based on models and other
Valuation methods (c) 413 6,130 2,492 2,244 11,279
------ ------ ------ ------ -------
Total $2,012 $9,852 $3,100 $2,244 $17,208
====== ====== ====== ====== =======
I&M
Prices provided by other
External Sources (b) $17,626 $ 9,009 $1,473 $ - $28,108
Prices based on models and other
Valuation methods (c) 4,554 14,841 6,032 5,433 30,860
------- ------- ------ ------ -------
Total $22,180 $23,850 $7,505 $5,433 $58,968
======= ======= ====== ====== =======
OPCo
Prices provided by other
External Sources (b) $27,625 $13,505 $ 2,208 $ - $43,338
Prices based on models and other
Valuation methods (c) 7,137 22,246 9,042 8,143 46,568
------- ------- ------- ------ -------
Total $34,762 $35,751 $11,250 $8,143 $89,906
======= ======= ======= ====== =======
PSO
Prices provided by other
External Sources (b) $(4,924) $ 442 $ 72 $ - $(4,410)
Prices based on models and other
Valuation methods (c) (1,272) 728 296 267 19
-------- ------ ---- ---- -------
Total $(6,196) $1,170 $368 $267 $(4,391)
======== ====== ==== ==== =======
SWEPCo
Prices provided by other
External Sources (b) $(5,568) $ 507 $ 83 $ - $(4,977)
Prices based on models and other
Valuation methods (c) (1,438) 836 340 306 43
-------- ------ ---- ---- -------
Total $(7,006) $1,343 $423 $306 $(4,934)
======== ====== ==== ==== =======
WTU
Prices provided by other
External Sources (b) $220 $ 434 $ 71 $ - $ 725
Prices based on models and other
Valuation methods (c) 57 715 291 262 1,325
---- ------ ---- ---- ------
Total $277 $1,149 $362 $262 $2,050
==== ====== ==== ==== ======
(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.
Item 4. Submission of Matters to a Vote of Security Holders.
---------------------------------------------------
AEP
The annual meeting of shareholders was held in Columbus, Ohio, on April
23, 2002. The holders of shares entitled to vote at the meeting or their proxies
cast votes at the meeting with respect to the following three matters, as
indicated below:
1. Election of thirteen directors to hold office until the next
annual meeting and until their successors are duly elected. Each
nominee for director received the votes of shareholders as
follows:
Number of Shares Number of
Nominee Voted For Votes Withheld
E. R. Brooks 201,037,003 55,252,755
Donald M. Carlton 248,549,741 7,740,017
John P. DesBarres 252,026,061 4,263,697
E. Linn Draper, Jr. 249,765,263 6,524,495
Robert W. Fri 251,979,293 4,310,465
William R. Howell 247,814,513 8,475,245
Lester A. Hudson, Jr. 249,730,186 6,559,572
Leonard J. Kujawa 251,840,096 4,449,662
Richard L. Sandor 252,037,196 4,252,562
Thomas V. Shockley, III 251,929,822 4,359,936
Donald G. Smith 252,372,686 3,917,072
Linda Gillespie Stuntz 251,968,011 4,321,747
Kathryn D. Sullivan 249,653,889 6,635,869
2. Approve the appointment by the Board of Directors of Deloitte &
Touche LLP as independent auditors of AEP for the year 2002. The
proposal was approved by a vote of the shareholders as follows:
Votes FOR 244,793,710
Votes AGAINST 9,303,198
Votes ABSTAINED 6,062,395
Broker NON-VOTES* 0
3. Shareholder proposal submitted by Ronald Marsico. The proposal
was disapproved by a vote of the shareholders as follows:
Votes FOR 14,495,798
Votes AGAINST 192,849,019
Votes ABSTAINED 6,062,395
Broker NON-VOTES* 42,882,546
*A non-vote occurs when a nominee holding shares for a beneficial
owner votes on one proposal, but does not vote on another proposal because the
nominee does not have discretionary voting power and has not received
instructions from the beneficial owner.
APCo
The annual meeting of stockholders was held on April 23, 2002 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR
each of the following seven persons for election as directors and there were no
votes withheld and such persons were elected directors to hold office for one
year or until their successors are elected and qualify:
E. Linn Draper, Jr. Thomas V. Shockley, III
Henry W. Fayne Susan Tomasky
Armando A. Pena Joseph H. Vipperman
Robert P. Powers
CPL
Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 11, 2002, the following seven persons were
elected directors to hold office for one year or until their successors are
elected and qualify:
E. Linn Draper, Jr. Thomas V. Shockley III
Henry W. Fayne Susan Tomasky
Armando A. Pena Joseph H. Vipperman
Robert P. Powers
I&M
Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 23, 2002, the following thirteen persons were
elected directors to hold office for one year or until their successors are
elected and qualify:
Karl G. Boyd Robert P. Powers
E. Linn Draper, Jr. John R. Sampson
John E. Ehler Thomas V. Shockley, III
Henry W. Fayne David B. Synowiec
David L. Lahrman Susan Tomasky
Marc E. Lewis Joseph H. Vipperman
Susanne M. Moorman
OPCo
The annual meeting of shareholders was held on May 7, 2002 at 1
Riverside Plaza, Columbus, Ohio. At the meeting there were 27,952,473 votes cast
FOR:
1. Each of the following seven persons for election as directors and there
were no votes withheld and such persons were elected directors to hold
office for one year or until their successors are elected and qualify:
E. Linn Draper, Jr. Thomas V. Shockley, III
Henry W. Fayne Susan Tomasky
Armando A. Pena Joseph H. Vipperman
Robert P. Powers
2. Approval of amendment to Article Second of the Amended Articles of
Incorporation of OPCo providing that the principal office of OPCo is to
be located at 1 Riverside Plaza, Columbus, Franklin County, Ohio, and
there were no votes against, abstentions or broker non-votes.
SWEPCo
Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 10, 2002, the following seven persons were
elected directors to hold office for one year or until their successors are
elected and qualify:
E. Linn Draper, Jr. Thomas V. Shockley III
Henry W. Fayne Susan Tomasky
Armando A. Pena Joseph H. Vipperman
Robert P. Powers
Item 5. Other Information.
AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
Reference is made to page 29 of the Annual Report on Form 10-K for the
year ended December 31, 2001 (2001 10-K) for a discussion of regional haze. On
May 24, 2002, the D.C. Circuit Court issued an opinion and order vacating in
part and upholding in part the regional haze rule. The court held that Federal
EPA could not establish Best Available Retrofit Technology standards for entire
groups of emission sources without regard to improvement in visibility
attributable to individual source controls. Federal EPA has filed a petition
seeking rehearing by the entire D.C. Circuit Court.
AEP
Reference is made to pages 31 through 33 of the 2001 10-K for a
discussion of the Clean Water Act. On May 8, 2002, the U.S. District Court for
the Southern District of West Virginia issued an injunction prohibiting the U.S.
Army Corps of Engineers from issuing permits under Section 404 of the Clean
Water Act for the primary purpose of disposal of waste mining overburden and
spoil. On June 17, 2002, the court denied a request for stay filed by the U.S.
Department of Justice and intervenor, Kentucky Coal Association. The court
clarified that the decision only applies to the Corps' Huntington District. The
court also advised that the ruling does not apply to dredged material placed
back in the stream but does apply to activities other than coal mining that
require Section 404 permits. The intervenor-defendants have filed an appeal to
the U.S. Fourth Circuit Court of Appeals and the court has set a briefing
schedule. The effect on permitting activities of certain AEP subsidiaries under
Section 404 cannot be predicted but could be significant.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
OPCo
Exhibit 3(d) - Certificate of Amendment to Amended Articles of
Incorporation of OPCo, dated June 3, 2002.
Exhibit 3(e) - Composite copy of the Amended Articles of
Incorporation of OPCo (amended as of June 3, 2002).
AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
Exhibit 12 - Computation of Consolidated Ratio of Earnings to
Fixed Charges.
AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
Exhibit 99.1 - Certification of Chief Executive Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the United States
Code.
Exhibit 99.2 - Certification of Chief Financial Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the United States
Code.
(b) Reports on Form 8-K:
Company Reporting Date of Report Item Reported
AEP June 5, 2002 Item 5. Other Events and Regulation
FD Disclosure
Item 7. Financial Statements and
Exhibits
APCo June 13, 2002 Item 5. Other Events and Regulation
FD Disclosure
Item 7. Financial Statements and
Exhibits
AEP June 18, 2002 Item 5. Other Events and Regulation
FD Disclosure
SWEPCo June 20, 2002 Item 5. Other Events and Regulation
FD Disclosure
Item 7. Financial Statements and
Exhibits
KPCo June 25, 2002 Item 5. Other Events and Regulation
FD Disclosure
Item 7. Financial Statements and
Exhibits
AEGCo, CPL, CSPCo, I&M, OPCo, PSO, and WTU
No reports on Form 8-K were filed during the quarter ended June 30,
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: August 13, 2002