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