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 SEPTEMBER 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
Indicate by check mark whether American Electric Power Company, Inc. is an
accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes X No
Indicate by check mark whether AEP Generating Company, 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 are accelerated filers (as defined in Rule 12b-2 of
the Exchange Act).
Yes No X
The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at October 31, 2002 was 338,835,220.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended September 30, 2002
CONTENTS
Page
Glossary of Terms i - iii
Forward-Looking Information iv
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-3
Consolidated Financial Statements A-4 - A-8
AEP Generating Company:
Management's Narrative Analysis of Results of Operations B-1 - B-2
Financial Statements B-3 - B-6
Appalachian Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations C-1 - C-3
Consolidated Financial Statements C-4 - C-8
Central Power and Light Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations D-1 - D-3
Consolidated Financial Statements D-4 - D-8
Columbus Southern Power Company and Subsidiaries:
Management's Narrative Analysis of Results of Operations E-1 - E-2
Consolidated Financial Statements E-3 - E-7
Indiana Michigan Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations F-1 - F-3
Consolidated Financial Statements F-4 - F-8
Kentucky Power Company:
Management's Narrative Analysis of Results of Operations G-1 - G-2
Financial Statements G-3 - G-7
Ohio Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations H-1 - H-3
Consolidated Financial Statements H-4 - H-8
Public Service Company of Oklahoma and Subsidiary:
Management's Narrative Analysis of Results of Operations I-1 - I-2
Consolidated Financial Statements I-3 - I-7
Southwestern Electric Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations J-1 - J-2
Consolidated Financial Statements J-3 - J-7
West Texas Utilities Company:
Management's Narrative Analysis of Results of Operations K-1 - K-3
Financial Statements K-4 - K-8
Notes to Financial Statements L-1 - L-25
Item 2. Registrants' Combined Management's Discussion and Analysis of
Financial Condition, Accounting Policies and Other Matters M-1 - M-21
Item 3. Quantitative and Qualitative Disclosures About Market Risk N-1 - N-8
Item 4. Controls and Procedures O-1
Part II. OTHER INFORMATION
Item 5. Other Information P-1
Item 6. Exhibits and Reports on Form 8-K P-1
(a) Exhibits
Exhibit 12
Exhibit 99.1
Exhibit 99.2
(b) Reports on Form 8-K
SIGNATURES Q-1
CERTIFICATIONS R-1 - R-4
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 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.
ICR................................ Internal Cost Reconstruction.
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.
MTM................................ Mark-to-Market Accounting.
MW................................. Megawatt.
MWH................................ Megawatthour.
NEIL............................... Nuclear Electric Insurance Limited.
NOx................................ Nitrogen oxide.
NOx Rule........................... A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states
including seven of the states in which AEP companies 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 or leased 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.
SFAS 146........................... Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with
Exit or Disposal Activities.
SNF................................ Spent Nuclear Fuel.
SPP................................ Southwest Power Pool.
STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light
Company, an AEP electric utility subsidiary .
STPNOC............................. STP Nuclear Operating Company, a non-profit Texas Corporation which operates STP on behalf
of its joint owners including CPL.
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 regulation, oversight and/or
investigation of the energy sector or its participants.
o The ability of AEP to successfully control its costs.
o The success of acquiring new business ventures and disposing of
existing investments that no longer match our corporate profile.
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 banking, capital and wholesale power markets.
o Other risks and unforeseen events.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2002 vs. THIRD QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001
AEP's 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, coal and other commodities
o Coal mining, bulk commodity barging operations and other energy
supply related businesses
o Energy Delivery
o Domestic electricity transmission
o Domestic electricity distribution
o Other Investments
o Investments in foreign power and distribution projects
o Telecommunication services
Results of Operations
Net Income for the third quarter was $425 million, an increase of $4
million compared to third quarter 2001. Earnings per share for the quarter were
$1.25 compared to $1.31 in 2001, reflecting the effects of the sale of
additional shares in 2002. Regulated integrated utilities and wholesale sales
from our power plants showed strong increases in earnings when compared with the
same period last year. However, lower earnings from energy trading and a loss
from power generation in the United Kingdom offset the positives. AEP had Net
Income of $318 million year-to-date compared to $919 million in 2001.
Year-to-date earnings per share as of September 30, 2002 were $.97 compared to
$2.85 in 2001, reflecting the combined effect of equity sales, discontinued
operations and the cumulative effect of a change in accounting principle. The
year-to-date loss for transitional goodwill impairment related to SEEBOARD and
CitiPower resulted from the adoption of SFAS 142 (see Note 3) and has been
reported as a cumulative effect of a change in accounting principle retroactive
to January 1, 2002.
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Electricity Marketing and Trading* $ 314 18 $762 15
Gas Marketing and Trading (214) (22) 32 2
Domestic Energy Delivery* 81 8 138 5
Other Investments (27) (57) (58) (49)
----- ----
Total $ 154 4 $874 9
===== ====
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to domestic energy delivery.
The increase in Electricity Marketing and Trading revenues was primarily
due to strong wholesale and retail sales as a result of favorable weather
conditions in the third quarter. The increase in revenues year-to-date from Gas
Marketing and Trading can be attributed to an increase in volumes, as we
expanded our operations around Houston Pipe Line (HPL) which we acquired in June
2001. The decrease in Gas Marketing and Trading revenues in the third quarter
resulted from a decrease in net gains from financial trading which offset the
year-to-date increase attributed to the HPL acquisition. Other Investments
decreased in both periods due to the elimination of factoring of accounts
receivable of an unaffiliated utility. Prior to the third quarter of 2002, we
recorded and reported upon settlement, sales under forward trading contracts as
revenues and purchases under forward trading contracts as purchased energy
expenses. Effective July 1, 2002, we reclassified such forward trading revenues
and purchases on a net basis, as permitted by EITF 98-10 (see Note 2 and "New
Accounting Pronouncements" in "Registrants' Combined Management's Discussion and
Analysis of Financial Condition, Accounting Policies and Other Matters").
Changes in Operating Expenses
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Fuel and Purchased Energy:
Electricity Marketing $ 294 41 $ 329 16
Gas Marketing (23) (3) 520 30
Other Investments 1 25 2 20
Maintenance and Other Operation (135) (15) 171 6
Depreciation and Amortization 58 19 127 14
Taxes other Than Income Taxes (1) - 24 4
----- ------
Total $ 194 7 $1,173 15
===== ======
In the quarter and year-to-date, the increase in Fuel and Purchased
Energy expense was primarily attributable to an increase in power generation.
Net generation increased 3% due to increased demand for electricity and a
reduction in planned power plant maintenance outages for various plants from
2001. The year-to-date increase in Gas Marketing expense was primarily due to an
expansion of gas activity around our HPL pipeline assets.
For the quarter, the decrease in Maintenance and Other Operation expense
was due to a $35 million reduction in trading incentives, a $40 million
reduction in administration costs due to severance expense recorded in the prior
year, a $31 million reduction in other transmission and distribution expenses as
well as a $12 million decline in nuclear outage expenses due to the reduction
of planned outages. These favorable results were partially offset by an
impairment charge due to a writedown of utility assets resulting from the
inactivation of inefficient gas fired generating facilities at WTU of
approximately $34 million (see Note 10). Year-to-date Maintenance and Other
Operation expense increased largely as aresult of the expenses of recently
acquired businesses including Quaker Coal; MEMCO, a barging line; planned
material and labor costs incurred in connection with the construction of
gas-fired plants for third parties; HPL; and two power plants in the UK. These
cost increases were partially offset by a reduction in trading incentive
compensation.
Depreciation and Amortization expense for both periods increased due to
plants acquired, and a plant placed into service in late 2001 as well the
amortization of Texas generation related Regulatory Assets that were securitized
in early 2002.
For the year-to-date, period Taxes Other Than Income Taxes increased due
to recently acquired businesses including Quaker Coal, MEMCo and HPL and two
plants in the UK.
Other Changes
Other Income decreased in the year-to-date period due mainly to a gain
on the sale of the Frontera generating plant in 2001 partially offset by an
increase in both periods for other business development income due to the
increased volume of those projects as well as minority interest in 2002.
Other Expense increased in both periods due to an increase in expenses
on other business development projects expenses in 2002.
The increase in Income Taxes for the third quarter and the decrease in
Income Taxes for the year-to-date period were predominately due to a
corresponding increase/decrease in pre-tax income.
The decrease in Interest was primarily due to the refinancing of
long-term debt at favorable interest rates, a reduction in short-term interest
rates and lower outstanding balances of short-term debt.
In connection with the sale of CitiPower and SEEBOARD (see Note 4), we
had recorded a net loss totaling $432 million as of September 30, 2002. Within
the total net loss of $432 million is a $350 million transitional goodwill
impairment loss from the adoption of SFAS 142 (see Note 3) reported as a
cumulative effect of a change in accounting principle retroactive to January 1,
2002.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
REVENUES:
Electricity Marketing and Trading $2,086 $1,772 $ 5,875 $ 5,113
Gas Marketing and Trading 761 975 2,145 2,113
Domestic Electric Delivery 1,043 962 2,737 2,599
Other Investments 21 48 61 119
------ ------ ------- -------
TOTAL REVENUES 3,911 3,757 10,818 9,944
------ ------ ------- -------
EXPENSES:
Fuel and Purchased Energy:
Electricity Marketing 1,011 717 2,446 2,117
Gas Marketing 778 801 2,225 1,705
Other Investments 5 4 12 10
------ ------ ------- -------
TOTAL FUEL AND PURCHASED ENERGY 1,794 1,522 4,683 3,832
------ ------ ------- -------
Maintenance and Other Operation 770 905 2,857 2,686
Depreciation and Amortization 366 308 1,059 932
Taxes Other Than Income Taxes 198 199 560 536
------ ------ ------- -------
TOTAL EXPENSES 3,128 2,934 9,159 7,986
------ ------ ------- -------
OPERATING INCOME 783 823 1,659 1,958
OTHER INCOME 127 73 210 224
OTHER EXPENSE 89 52 137 99
LESS: INTEREST 180 215 566 650
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 3 2 8 7
MINORITY INTEREST IN FINANCE SUBSIDIARY 9 5 27 5
------ ------ ------- -------
INCOME BEFORE INCOME TAXES 629 622 1,131 1,421
INCOME TAXES 242 221 429 537
------ ------ ------- -------
INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS,
EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A
CHANGE IN ACCOUNTING PRINCIPLE 387 401 702 884
Discontinued Operations (net of tax) 38 2 (34) 65
Extraordinary Loss - (net of tax) - - - (48)
Cumulative Effect of a Change in Accounting
Principle - (net of tax) (See Note 3) - 18 (350) 18
------ ------ ------- -------
NET INCOME $ 425 $ 421 $ 318 $ 919
====== ====== ======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 339 322 329 322
=== === === ===
EARNINGS (LOSS) PER SHARE (BASIC AND DILUTIVE):
Income Before Discontinued Operations,
Extraordinary Item and Cumulative Effect of a
Change in Accounting Principle $1.14 $1.24 $ 2.14 $ 2.74
Discontinued Operations 0.11 0.01 (0.10) 0.20
Extraordinary Loss - - - (0.15)
Cumulative Effect of a Change in Accounting
Principle - 0.06 (1.07) 0.06
----- ----- ------ ------
EARNINGS PER SHARE (BASIC AND DILUTIVE) $1.25 $1.31 $ 0.97 $ 2.85
===== ===== ====== ======
CASH DIVIDENDS PAID PER SHARE $0.60 $0.60 $1.80 $1.80
===== ===== ===== =====
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in millions)
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents $ 566 $ 231
Accounts Receivable (net) 2,546 1,649
Fuel, Materials and Supplies 1,227 1,046
Energy Trading and Derivative Contracts 7,897 8,536
Other 1,361 639
------- -------
TOTAL CURRENT ASSETS 13,597 12,101
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 17,750 17,477
Transmission 6,237 5,764
Distribution 9,474 9,309
Other (including gas, coal mining and
nuclear fuel) 4,316 4,530
Construction Work in Progress 1,296 1,088
------- -------
Total Property, Plant and Equipment 39,073 38,168
Accumulated Depreciation and Amortization 16,256 15,403
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 22,817 22,765
------- -------
REGULATORY ASSETS 2,394 3,162
------- -------
SECURITIZED TRANSITION ASSET 743 -
------- -------
INVESTMENTS IN POWER, DISTRIBUTION AND
COMMUNICATIONS PROJECTS 521 633
------- -------
ASSETS OF DISCONTINUED OPERATIONS - 3,985
------- -------
GOODWILL 461 392
------- -------
INTANGIBLE ASSETS 35 33
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 3,027 2,368
------- -------
OTHER ASSETS 1,921 1,842
------- -------
TOTAL $45,516 $47,281
======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 2,662 $ 1,916
Short-term Debt 3,234 4,011
Long-term Debt Due Within One Year 825 1,114
Energy Trading And Derivative Contracts 8,008 8,288
Other 1,937 1,935
------- -------
TOTAL CURRENT LIABILITIES 16,666 17,264
------- -------
LONG-TERM DEBT 8,719 8,440
------- -------
EQUITY UNIT SENIOR NOTES 371 -
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2,693 2,176
------- -------
DEFERRED INCOME TAXES 4,444 4,469
------- -------
DEFERRED INVESTMENT TAX CREDITS 468 491
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 773 844
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 187 194
------- -------
OTHER NONCURRENT LIABILITIES 1,304 1,334
------- -------
LIABILITIES OF DISCONTINUED OPERATIONS - 2,613
------- -------
COMMITMENTS AND CONTINGENCIES (Note 9)
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 759 750
------- -------
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. . . . .347,835,212 331,234,997
(8,999,992 shares were held in treasury at
September 30, 2002 and December 31, 2001) 2,261 2,153
Paid-in Capital 3,394 2,906
Accumulated Other Comprehensive Income (Loss) (28) (126)
Retained Earnings 3,039 3,296
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 8,666 8,229
------- -------
TOTAL $45,516 $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)
Nine Months Ended September 30,
2002 2001
---- ----
OPERATING ACTIVITIES: (in millions)
Net Income $ 318 $ 919
Deduct Income (Add Loss) from Discontinued Operations 384 (65)
------ ------
Net Income from Continuing Operations 702 854
Adjustments for Noncash Items:
Depreciation and Amortization 1,080 960
Deferred Federal Income Taxes (86) 119
Deferred Investment Tax Credits (21) (26)
Deferred Costs Under Fuel Clause Mechanisms (57) 240
Miscellaneous Accrued Expenses 138 (66)
Extraordinary Loss - Effects of Deregulation - 48
Cumulative Effect of Accounting Change - (18)
Mark to Market on Open Energy Trading and Derivative Contracts (145) (434)
Realized Mark to Market on Settled Energy Trading and Derivative Contracts 362 (109)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (882) 958
Fuel, Materials and Supplies (176) (119)
Accrued Revenues (255) 7
Prepayments and Other (387) (81)
Accounts Payable 789 (934)
Taxes Accrued 128 153
Interest Accrued 109 60
Change in Other Assets (417) (381)
Change in Other Liabilities (127) (66)
------- -------
Net Cash Flows From Operating Activities 755 1,165
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (1,147) (1,187)
Purchase of Houston Pipe Line - (727)
Net Proceeds from Sale of CitiPower 175 -
Net Proceeds from Sale of Seeboard 941 -
Net Proceeds from Sale of Yorkshire - 383
Net Proceeds from Sale of Frontera - 265
Other 2 (54)
------- -------
Net Cash Flows Used For Investing Activities (29) (1,320)
------- -------
FINANCING ACTIVITIES:
Issuance of Common Stock 656 9
Issuance of Minority Interest - 750
Issuance of Long-term Debt 1,819 1,764
Issuance of Equity Unit Senior Notes 334 -
Change in Short-term Debt (net) (777) (995)
Retirement of Cumulative Preferred Stock (10) (5)
Retirement of Long-term Debt (1,819) (846)
Dividends Paid on Common Stock (590) (580)
------- -------
Net Cash Flows From (Used For) Financing Activities (387) 97
------- -------
Effect of Exchange Rate Change on Cash (4) (7)
------- -------
Net Increase (Decrease) in Cash and Cash Equivalents 335 (65)
------- -------
Net Increase (Decrease) in Cash and Cash Equivalents from Discontinued Operations (102) 7
Cash and Cash Equivalents at Beginning of Period 333 342
------- -------
Cash and Cash Equivalents Continuing Operations - Beginning of Period 231 349
------- -------
Cash and Cash Equivalents at End of Period $ 566 $ 284
------- -------
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was
$328 million and $469 million and for income taxes was $242 million and $208
million in 2002 and 2001, respectively. Noncash acquisitions under capital
leases were $1 million in 2002 and $39 million in 2001.
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 (580) (580)
Other (7) 9 2
------
7,485
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes:
Currency Translation Adjustment (21) (21)
Unrealized Gain on
Hedged Derivatives 2 2
Minimum Pension Liability (6) (6)
Net Income 919 919
------
Total Comprehensive Income 894
------ ------ ------ ----- ------
SEPTEMBER 30, 2001 $2,153 $2,916 $3,438 $(128) $8,379
====== ====== ====== ===== ======
JANUARY 1, 2002 $2,153 $2,906 $3,296 $(126) $8,229
Issuance of Common Stock 108 568 676
Common Stock Dividends (590) (590)
Other (80) 15 (65)
------
8,250
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes:
Currency Translation Adjustment 97 97
Unrealized Loss on
Securities Available for sale (3) (3)
Unrealized Gain on Cash Flow
Hedges 4 4
Net Income 318 318
------
Total Comprehensive Income 416
------ ------ ------ ---- ------
SEPTEMBER 30, 2002 $2,261 $3,394 $3,039 $(28) $8,666
====== ====== ====== ====- ======
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2002 vs. THIRD QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001
AEGCo is engaged in the generation and wholesale sale of electric power
to two affiliates under long-term agreements.
Operating Revenues are derived from the sale of Rockport Plant energy
and capacity to two affiliated companies pursuant to FERC approved long-term
unit power agreements. The unit power agreements provide for recovery of costs
including a FERC approved rate of return on common equity and a return on other
capital net of temporary cash investments.
Results of Operations
Net Income decreased $104,000 or 5% for the third quarter and $536,000
or 9% 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.
Changes in Revenues
The decreases in Operating Revenues of $1,429,000 or 2% for the third
quarter and $10,922,000 or 6% for the year-to-date period resulted from
decreases in recoverable expenses, primarily Fuel.
Changes in Operating Expenses
Operating expenses declined 2% in the third quarter and 6% for the
year-to-date period as follows:
Increase (Decrease)
-------------------
Third Quarter Year-to-Date
------------- ------------
(in thousands) % (in thousands) %
-------------- - -------------- -
Fuel $(1,441) (5) $(10,312) (14)
Other Operation (506) (20) 1,404 18
Maintenance 69 5 (474) (6)
Depreciation 30 1 117 1
Taxes Other Than Income Taxes 149 15 41 1
Income Taxes 449 N.M. (1,101) (43)
------- --------
Total $(1,250) (2) $(10,325) (6)
======= ========
N.M. = Not Meaningful
Fuel expense, which includes coal transportation cost and coal trading
gains, decreased in the year-to-date period due to lower average fuel costs and
a decrease in generation. Lower fuel cost contributed $6,600,000 of the decrease
while decreased generation contributed $3,700,000. The decrease in generation
reflects longer outages for planned maintenance and system enhancements in 2002.
Other Operation expense decreased in the third quarter due to a decrease
in the FERC assessment and lower costs allocated from affiliates. The increase
in Other Operation expense for the year-to-date period is primarily due to
higher costs for employee benefits and property insurance.
Maintenance expense for the year-to-date period decreased even though
the duration of outages lengthened. In 2002, due to the capital nature of the
projects, more labor and related costs are being capitalized as part of system
enhancements instead of expensed as maintenance projects.
Taxes Other Than Income Taxes increased due to increased employer
expense for employment taxes in the third quarter due to a change in estimate
from the second quarter's level of expense.
The decrease in Income Taxes attributable to operations for the
year-to-date period is primarily due to a change in estimate 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 during
the second and third quarters of 2001 resulting in higher comparable Income
Taxes for the third quarter of 2002.
Other Changes
Interest Charges declined 14% in the third quarter and 12% 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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES - Sales to
AEP Affiliates $55,988 $57,417 $159,219 $170,141
------- ------- -------- --------
OPERATING EXPENSES:
Fuel 26,702 28,143 65,737 76,049
Rent - Rockport Plant Unit 2 17,071 17,071 51,212 51,212
Other Operation 2,023 2,529 9,259 7,855
Maintenance 1,484 1,415 6,838 7,312
Depreciation 5,643 5,613 16,918 16,801
Taxes Other Than Income Taxes 1,150 1,001 3,110 3,069
Income Taxes 479 30 1,438 2,539
------- ------- -------- --------
TOTAL OPERATING EXPENSES 54,552 55,802 154,512 164,837
------- ------- -------- --------
OPERATING INCOME 1,436 1,615 4,707 5,304
NONOPERATING INCOME 74 5 108 5
NONOPERATING EXPENSES (8) (3) 98 7
NONOPERATING INCOME TAX CREDITS 886 957 2,541 2,716
INTEREST CHARGES 457 529 1,700 1,924
------- ------- -------- -------
NET INCOME $ 1,947 $ 2,051 $ 5,558 $ 6,094
======= ======= ======== =======
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $15,272 $11,847 $13,761 $ 9,722
NET INCOME 1,947 2,051 5,558 6,094
CASH DIVIDENDS DECLARED 1,050 959 3,150 2,877
------- ------- ------- -------
BALANCE AT END OF PERIOD $16,169 $12,939 $16,169 $12,939
======= ======= ======= =======
The common stock of AEGCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $639,487 $638,297
General 2,883 3,012
Construction Work in Progress 12,295 6,945
-------- --------
Total Electric Utility Plant 654,665 648,254
Accumulated Depreciation 353,080 337,151
-------- --------
NET ELECTRIC UTILITY PLANT 301,585 311,103
-------- --------
OTHER PROPERTY AND INVESTMENTS 119 119
-------- --------
CURRENT ASSETS:
Cash and Cash Equivalents - 983
Advances to Affiliates 14,148 -
Accounts Receivable:
Affiliated Companies 33,714 22,344
Miscellaneous 147 147
Fuel - at average cost 13,048 15,243
Materials and Supplies - at average cost 4,934 4,480
Prepayments 83 244
-------- --------
TOTAL CURRENT ASSETS 66,074 43,441
-------- --------
REGULATORY ASSETS 5,030 5,207
-------- --------
DEFERRED CHARGES 2,010 1,471
-------- --------
TOTAL ASSETS $374,818 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
September 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 16,169 13,761
-------- --------
Total Common Shareholder's Equity 40,603 38,195
Long-term Debt 44,800 44,793
-------- --------
TOTAL CAPITALIZATION 85,403 82,988
-------- --------
OTHER NONCURRENT LIABILITIES 340 76
-------- --------
CURRENT LIABILITIES:
Advances from Affiliates - 32,049
Accounts Payable:
General 11,684 7,582
Affiliated Companies 28,628 1,654
Taxes Accrued 9,002 4,777
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Other 2,723 3,481
-------- --------
TOTAL CURRENT LIABILITIES 75,464 54,506
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
PLANT UNIT 2 112,439 116,617
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credit 53,800 56,304
Amounts Due to Customers for Income Taxes 20,840 22,725
-------- --------
TOTAL REGULATORY LIABILITIES 74,640 79,029
-------- --------
DEFERRED INCOME TAXES 26,532 27,975
-------- --------
DEFERRED CREDITS - 150
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $374,818 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 5,558 $ 6,094
Adjustment for Noncash Items:
Depreciation 16,918 16,801
Deferred Income Taxes (3,328) (4,409)
Deferred Investment Tax Credits (2,504) (2,509)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (4,178) (4,178)
Deferred Property Taxes (881) (922)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (11,370) 4,742
Fuel, Materials and Supplies 1,741 (4,595)
Accounts Payable 31,076 1,985
Taxes Accrued 4,225 7,201
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets 243 (1,840)
Change in Other Liabilities (644) (1,860)
-------- --------
Net Cash Flow From Operating Activities 55,320 34,974
-------- --------
INVESTING ACTIVITIES - Construction Expenditures (6,956) (3,120)
-------- --------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) (46,197) (31,546)
Dividends Paid (3,150) (2,877)
-------- --------
Net Cash Flows Used For Financing Activities (49,347) (34,423)
-------- --------
Net Decrease in Cash and Cash Equivalents (983) (2,569)
Cash and Cash Equivalents at Beginning of Period 983 2,757
-------- --------
Cash and Cash Equivalents at End of Period $ - $ 188
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,983,000 and $1,489,000
and for income taxes was $2,442,000 and $1,352,000 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
THIRD QUARTER 2002 vs. THIRD 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 Power Pool's generating capacity is allocated among
its 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.
Results of Operations
Net Income increased $24 million or 78% for the quarter and $27 million
or 21% year-to-date period due to higher retail sales and cost reductions.
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Electricity Marketing and Trading $39 16 $ 7 1
Energy Delivery* (5) (3) (11) (2)
Sales to AEP Affiliates 6 15 6 5
--- ---
Total $40 9 $ 2 -
=== ===
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The increase in revenues for the quarter was due primarily to warmer
summer weather as the third quarter of 2002 saw a 31% increase in cooling degree
days over third quarter of 2001. Year-to-date revenues were comparable to those
of last year as current quarter increases offset lower revenues for the first
six months which were lower primarily as a result of lower demand caused by mild
winter weather. Sales to AEP Affiliates increased quarter to quarter and year to
year due to available generation to be delivered to the AEP Power Pool.
Changes in Operating Expenses
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $ 16 17 $ 50 18
Electricity Marketing Purchases 12 115 24 83
Purchases from AEP Affiliates (15) (21) (88) (33)
Other Operation (8) (11) (10) (5)
Maintenance - - (13) (13)
Depreciation and Amortization 2 3 7 6
Taxes Other Than Income Taxes (1) (3) (1) (2)
Income Taxes 13 66 14 18
---- ----
Total $ 19 5 $(17) (2)
==== ====
Fuel expense increased for the quarter and year-to-date as a result of
an increase in APCo generation. Mountaineer, Amos, and Glen Lyn plants had
undergone boiler plant maintenance in 2001 which resulted in increased
availability and a decrease in maintenance in 2002.
Electricity Marketing Purchases increased for the quarter and
year-to-date as a result of increased purchases from third parties for resale to
wholesale customers and to meet internal demand.
The overall decrease for both periods in Purchases from AEP Affiliates
is a result of increased internal generation due to plant availability as
disclosed above in the discussion of Fuel expense.
The decrease in Other Operation expense for both periods is due
primarily to a decrease in transmission equalization charges caused by a
reduction in APCo's MLR ratio, a decrease in power trading incentive
compensation expense, and energy delivery severance accruals recorded in 2001
for which there was no comparable activity in 2002. These favorable variances
were partially offset by an increase in insurance premiums and other employee
benefit costs.
The decrease in Maintenance expense year-to-date is primarily due to
boiler plant maintenance at Amos, Mountaineer, and Glen Lyn plants in the year
2001 for which there was less activity in 2002. In addition, there were fewer
maintenance needs for electric plant, station equipment, and company owned
structures and improvements.
Depreciation and Amortization expense increased during both periods due
to increased amortization for the net generation-related regulatory assets
related to the Company's Virginia and West Virginia jurisdictions that are being
recovered through regulated rates. Additionally, investment in production plant
in service, primarily emission control related, also contributed to the increase
in depreciation and amortization expense.
The increase in Income Taxes for the quarter and year-to-date was due to
an increase in pre-tax income.
Other Changes
Nonoperating Income for the quarter increased due to a net gain in power
trading activity. The Nonoperating Income decrease year-to-date was due to a
decrease in net power trading gains driven by a decline in market prices.
Year-to-date Interest Charges decreased primarily as a result of lower
AEP money pool balances and interest rates and the retirement of first mortgage
bonds in 2001.
Nonoperating Income Tax Expense increased in both periods due to the
increase in nonoperating pre-tax income and year-to-date due to a change in the
allocation of tax savings from AEP.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $277,796 $ 238,819 $ 785,206 $ 777,803
Energy Delivery 150,236 155,566 444,706 455,587
Sales to AEP Affiliates 46,250 40,065 138,990 132,676
-------- ---------- ---------- ----------
TOTAL OPERATING REVENUES 474,282 434,450 1,368,902 1,366,066
-------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 107,514 91,594 322,164 272,119
Purchased Power:
Electricity Marketing 23,047 10,741 51,508 28,106
AEP Affiliates 58,395 73,951 177,892 265,614
Other Operation 67,255 75,239 197,631 207,266
Maintenance 32,053 31,812 85,542 98,663
Depreciation and Amortization 47,692 46,177 141,373 133,950
Taxes Other Than Income Taxes 23,881 24,578 73,926 75,263
Income Taxes 33,080 19,977 90,723 77,190
-------- ---------- ---------- ----------
TOTAL OPERATING EXPENSES 392,917 374,069 1,140,759 1,158,171
-------- ---------- ---------- ----------
OPERATING INCOME 81,365 60,381 228,143 207,895
NONOPERATING INCOME 6,627 5,655 26,644 47,746
NONOPERATING EXPENSES 4,865 8,108 9,170 31,800
NONOPERATING INCOME TAX EXPENSE (CREDIT) 538 (1,535) 5,622 4,041
INTEREST CHARGES 28,642 29,146 84,099 91,277
-------- ---------- ---------- ----------
NET INCOME 53,947 30,317 155,896 128,523
PREFERRED STOCK DIVIDEND REQUIREMENTS 502 502 1,508 1,508
-------- ---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 53,445 $ 29,815 $ 154,388 $ 127,015
======== ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $53,947 $30,317 $155,896 $128,523
OTHER COMPREHENSIVE INCOME (LOSS):
Cash Flow Power Hedges (1,731) - 486 -
Cash Flow Interest Rate Hedge 108 - (2,020) -
Foreign Currency Exchange Rate
Hedge 4 673 147 44
------- ------- -------- --------
COMPREHENSIVE INCOME $52,328 $30,990 $154,509 $128,567
======= ======= ======== ========
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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $189,773 $152,987 $150,797 $120,584
NET INCOME 53,947 30,317 155,896 128,523
-------- -------- -------- --------
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 30,984 32,399 92,952 97,196
Preferred Stock 361 361 1,082 1,082
Capital Stock Expense 142 141 426 426
-------- -------- -------- --------
BALANCE AT END OF PERIOD $212,233 $150,403 $212,233 $150,403
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,198,392 $2,093,532
Transmission 1,219,411 1,222,226
Distribution 1,927,797 1,887,020
General 252,295 257,957
Construction Work in Progress 214,973 203,922
---------- ----------
Total Electric Utility Plant 5,812,868 5,664,657
Accumulated Depreciation and Amortization 2,400,618 2,296,481
---------- ----------
NET ELECTRIC UTILITY PLANT 3,412,250 3,368,176
---------- ----------
OTHER PROPERTY AND INVESTMENTS 57,235 53,736
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE
CONTRACTS 347,588 316,249
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 9,428 13,663
Accounts Receivable:
Customers 113,359 113,371
Affiliated Companies 135,972 63,368
Miscellaneous 23,011 11,847
Allowance for Uncollectible Accounts (2,345) (1,877)
Fuel - at average cost 50,064 56,699
Materials and Supplies - at average cost 61,308 59,849
Accrued Utility Revenues 23,360 30,907
Energy Trading and Derivative Contracts 475,513 566,284
Prepayments and Other 25,643 16,018
---------- ----------
TOTAL CURRENT ASSETS 915,313 930,129
---------- ----------
REGULATORY ASSETS 384,920 397,383
---------- ----------
DEFERRED CHARGES 41,377 42,265
---------- ----------
TOTAL ASSETS $5,158,683 $5,107,938
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 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 716,212 715,786
Accumulated Other Comprehensive Income (Loss) (1,727) (340)
Retained Earnings 212,233 150,797
---------- ----------
Total Common Shareowner's Equity 1,187,176 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 1,568,904 1,476,552
---------- ----------
TOTAL CAPITALIZATION 2,784,730 2,631,903
---------- ----------
OTHER NONCURRENT LIABILITIES 84,725 84,104
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 155,007 80,007
Advances from Affiliates 165,177 291,817
Accounts Payable - General 129,869 127,597
Accounts Payable - Affiliated Companies 55,298 84,518
Taxes Accrued 95,243 55,583
Customer Deposits 26,296 13,177
Interest Accrued 35,257 21,770
Energy Trading and Derivative Contracts 445,532 549,703
Other 70,811 79,089
---------- ----------
TOTAL CURRENT LIABILITIES 1,178,490 1,303,261
---------- ----------
DEFERRED INCOME TAXES 713,795 703,575
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 35,033 38,328
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 272,862 257,129
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 89,048 89,638
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $5,158,683 $5,107,938
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 155,896 $ 128,523
Adjustments for Noncash Items:
Depreciation and Amortization 141,457 134,034
Deferred Income Taxes 10,257 30,506
Deferred Investment Tax Credits (3,295) (3,318)
Amortization of Deferred Property Taxes 13,573 13,480
Mark-to-Market Energy Trading and Derivative Contracts (27,710) (99,410)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (83,288) 105,134
Fuel, Materials and Supplies 5,176 (12,162)
Accrued Utility Revenues 7,547 46,655
Accounts Payable (26,948) (34,550)
Taxes Accrued 39,660 14,630
Interest Accrued 13,487 19,104
Change in Other Assets (21,270) (22,917)
Change in Other Liabilities 4,618 (17,936)
---------- ---------
Net Cash Flows From Operating Activities 229,160 301,773
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (175,314) (185,185)
Proceeds from Sale of Property and Other 3,483 1,182
--------- ---------
Net Cash Flows Used For Investing Activities (171,831) (184,003)
--------- ---------
FINANCING ACTIVITIES:
Change in Short-term Debt (net) - (191,495)
Change in Advances to Affiliates (net) (126,640) 217,925
Issuance of Long-term Debt 444,110 124,588
Retirement of Long-term Debt (285,000) (175,000)
Dividends Paid on Common Stock (92,952) (97,196)
Dividends Paid on Cumulative Preferred Stock (1,082) (1,082)
--------- ---------
Net Cash Flows Used For Financing Activities (61,564) (122,260)
--------- ---------
Net Decrease in Cash and Cash Equivalents (4,235) (4,490)
Cash and Cash Equivalents at Beginning of Period 13,663 5,847
--------- ---------
Cash and Cash Equivalents at End of Period $ 9,428 $ 1,357
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $68,305,000 and
$70,286,000 and for income taxes was $38,425,000 and $21,521,000 in 2002 and
2001, respectively. There were no noncash payments for the capital leases in
2002. Noncash acquisitions under capital leases were $2,576,000 in 2001.
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
THIRD QUARTER 2002 vs. THIRD QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001
CPL is a public utility engaged in the generation, purchase, 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 its affiliated REP in Texas.
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.
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 REP, 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 affiliated REP. Pending regulatory approval, CPL will separate its
generation from its transmission and distribution operations. The affiliated REP
is a separate legal entity that is an AEP subsidiary that is not owned by or
consolidated with CPL.
Since the affiliated REP is the electricity supplier to retail customers
in the ERCOT area, CPL sells its generation to the affiliated REP and other
market participants and provides transmission and distribution services to
retail customers in the CPL service territory. As a result of the formation of
the affiliated REP, effective January 1, 2002, CPL no longer supplies
electricity directly to retail customers. The implementation of affiliated REPs
as suppliers to retail customers has caused a significant shift in CPL's sales
as described below under "Results of Operations."
Results of Operations
Third quarter Net Income increased $10 million or 12% primarily due to
decreased interest charges and the absence in 2002 of special tax assessments
recorded in the third quarter of 2001. Year-to-date Net Income decreased $20
million or 12% primarily due to a slow economic recovery and a significant
decline in wholesale margins.
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Electricity Marketing and Trading* $(320) (91) $(877) (93)
Energy Delivery* (97) (57) (209) (47)
Sales to AEP Affiliates 436 N.M. 841 N.M.
----- -----
Total $ 19 4 $(245) (17)
===== =====
*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 electricity sales in the ERCOT region as of January 1,
2002 and a decrease in energy trading margins offset in part by the ICR
adjustments (see Note 6). Also contributing to the decrease was a decline in
wholesale power prices due to soft market demand.
Sales to AEP Affiliates increased primarily due to increased revenues to
the newly-created affiliated REP. Although CPL sold electricity to the
affiliated REP instead of directly to retail customers, total revenues
decreased due to lower wholesale prices.
For the quarter, the effect of the ICR adjustments and revenue
associated with securitized assets offset negative wholesale effects (see
Note 6).
Changes in Operating Expenses
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Fuel $(58) (48) $(213) (51)
Electricity Marketing 81 117 31 24
Purchases from AEP Affiliates (27) (162) (34) (77)
Other Operation (2) (3) (16) (7)
Maintenance 1 10 (8) (17)
Depreciation and Amortization 29 87 36 28
Taxes Other Than Income Taxes (10) (28) 5 7
Income Taxes - - (25) (25)
---- -----
Total $ 14 3 $(224) (19)
==== =====
Fuel expense decreased both for the quarter and year-to-date due to a
decrease in the average unit cost of fuel and decreased generation.
The increase in Electricity Marketing expense and the decrease in
Purchases from AEP Affiliates is due to higher MWH purchases from the market at
prices lower than CPL's generation cost. ICR adjustments in the third quarter
also had the effect of increasing Electricity Marketing expense and decreasing
Affiliates Purchase Power, resulting in a negative Affiliated Purchase Power
expense for the quarter (see Note 6).
Other Operation expense decreased both for the quarter and year-to-date
due primarily to the elimination of factoring of accounts receivable and lower
ERCOT transmission related expenses.
Maintenance expense decreased for the year due to a refueling outage
for STP during 2001.
The increase in Depreciation and Amortization is attributable to the
amortization of regulatory assets that were securitized in the first quarter of
2002, offset by the reduction of excess earnings expense in 2002 under Texas
Restructuring Legislation.
The increase year-to-date in Taxes Other Than Income Taxes resulted
primarily from higher local franchise taxes, offset by one-time third quarter
2001 assessments and decreased gross receipts tax, due to deregulation. For the
quarter, the decrease was primarily attributable to the one-time third quarter
2001 assessments described above.
The decrease in Income Taxes for the year-to-date period is due to a
decrease in pre-tax income.
Other Changes
Nonoperating Income and Nonoperating Expenses increased significantly
during the quarter and the year-to-date period as a result of increased
non-utility revenue and expenses associated with energy related construction
projects for third parties, offset in part by decreased interest income.
Interest Charges decreased primarily due to the issuance of lower
interest rates securitization bonds used to refinance regulatory assets in
accordance with the Texas Restructuring Legislation.
Nonoperating Income Tax Expense decreased both for the quarter and
year-to-date due to the recording of the investment tax credit amortization
related to power plants as Nonoperating Income Tax Credits since the time of
deregulation of CPL's power plants.
As a result of CPL's recent ability to purchase electricity at a
significantly lower price than its current cost to generate electricity, CPL
proposed in September 2002 to "inactivate" various, high-cost gas fired
generating facilities. CPL recorded an impairment charge in the third quarter
2002 of approximately $100 million related to these plants which was deferred
and recorded in Regulatory Assets, to be included as a stranded cost in the
Texas 2004 true-up proceeding (see Note 10).
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $ 31,569 $351,532 $ 66,172 $ 943,584
Energy Delivery 73,489 170,571 240,066 449,425
Sales to AEP Affiliates 441,202 5,014 879,323 37,440
-------- -------- ---------- ----------
TOTAL OPERATING REVENUES 546,260 527,117 1,185,561 1,430,449
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 63,657 121,933 207,941 420,965
Purchased Power:
Electricity Marketing 151,012 69,748 160,996 129,698
Affiliates (10,433) 16,876 10,058 43,685
Other Operation 71,023 73,543 208,984 224,803
Maintenance 15,239 13,827 40,980 49,109
Depreciation and Amortization 62,242 33,257 165,012 129,235
Taxes Other Than Income Taxes 24,774 34,379 76,170 71,197
Income Taxes 50,542 50,956 77,452 102,656
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES 428,056 414,519 947,593 1,171,348
-------- -------- ---------- ----------
OPERATING INCOME 118,204 112,598 237,968 259,101
NONOPERATING INCOME 10,234 4,690 24,237 7,192
NONOPERATING EXPENSES 10,184 979 23,049 2,626
NONOPERATING INCOME TAX EXPENSE (CREDIT) (1,522) 171 (2,037) 928
INTEREST CHARGES 26,393 32,436 89,830 91,488
-------- -------- ---------- ----------
NET INCOME 93,383 83,702 151,363 171,251
GAIN ON REACQUIRED PREFERRED STOCK 4 - 4 -
LESS: PREFERRED STOCK DIVIDEND
REQUIREMENTS 60 60 181 181
-------- -------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 93,327 $ 83,642 $ 151,186 $ 171,070
======== ======== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $93,383 $83,702 $151,363 $171,251
OTHER COMPREHENSIVE INCOME
Cash Flow Power Hedges (205) - 58 -
------- ------- -------- --------
COMPREHENSIVE INCOME $93,178 $83,702 $151,421 $171,251
======= ======= ======== ========
The common stock of CPL 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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $807,052 $805,619 $826,197 $792,219
NET INCOME 93,383 83,702 151,363 171,251
DEDUCTIONS (ADDITIONS):
Capital Stock Gains (4) - (4) -
Cash Dividends Declared:
Common Stock 38,501 37,015 115,505 111,043
Preferred Stock 60 60 181 181
-------- -------- -------- --------
BALANCE AT END OF PERIOD $861,878 $852,246 $861,878 $852,246
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,726,661 $3,169,421
Transmission 699,834 663,655
Distribution 1,300,353 1,279,037
General 244,134 241,137
Construction Work in Progress 181,179 169,075
Nuclear Fuel 258,059 247,382
---------- ----------
Total Electric Utility Plant 5,410,220 5,769,707
Accumulated Depreciation and Amortization 2,199,635 2,446,027
---------- ----------
NET ELECTRIC UTILITY PLANT 3,210,585 3,323,680
---------- ----------
OTHER PROPERTY AND INVESTMENTS 56,086 47,950
---------- ----------
SECURITIZED TRANSITION ASSET 742,766 -
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 21,874 72,502
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 56,638 10,909
Accounts Receivable:
General 114,134 38,459
Affiliated Companies 189,442 6,249
Allowance for Uncollectible Accounts (391) (186)
Fuel Inventory - at LIFO cost 42,232 38,690
Materials and Supplies - at average cost 58,147 55,475
Energy Trading and Derivative Contracts 35,211 212,979
Prepayments and Other Current Assets 5,007 2,742
---------- ----------
TOTAL CURRENT ASSETS 500,420 365,317
---------- ----------
REGULATORY ASSETS 374,097 226,812
---------- ----------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 161,552 959,294
---------- ----------
NUCLEAR DECOMMISSIONING TRUST FUND 93,385 98,600
---------- ----------
DEFERRED CHARGES 93,121 21,837
---------- ----------
TOTAL ASSETS $5,253,886 $5,115,992
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 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 September 30, 2002
6,755,535 Shares at December 31, 2001 $ 55,292 $ 168,888
Paid-in Capital 132,607 405,016
Accumulated Other Comprehensive Income 58 -
Retained Earnings 861,878 826,197
---------- ----------
Total Common Shareowner's Equity 1,049,835 1,400,101
Preferred Stock 5,941 5,951
CPL - Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of CPL 136,250 136,250
Long-term Debt 1,371,124 988,768
---------- ----------
TOTAL CAPITALIZATION 2,563,150 2,531,070
---------- ----------
OTHER NONCURRENT LIABILITIES 13,571 10,905
---------- ----------
CURRENT LIABILITIES:
Short-term Debt - Affiliates 200,000 -
Long-term Debt Due Within One Year 123,087 265,000
Advances from Affiliates 552,648 354,277
Accounts Payable - General 84,410 65,307
Accounts Payable - Affiliated Companies 13,892 49,301
Customer Deposits 982 26,744
Over Recovered Fuel 70,314 57,762
Taxes Accrued 144,710 83,512
Interest Accrued 35,354 18,524
Energy Trading and Derivative Contracts 30,695 219,486
Other 22,447 18,076
--------- ----------
TOTAL CURRENT LIABILITIES 1,278,539 1,157,989
---------- ----------
DEFERRED INCOME TAXES 1,171,257 1,163,795
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 118,987 122,892
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 17,829 62,138
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 90,553 67,203
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $5,253,886 $5,115,992
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended September 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 151,363 $ 171,251
Adjustments for Noncash Items:
Depreciation and Amortization 165,012 129,235
Deferred Income Taxes (14,620) (50,506)
Deferred Investment Tax Credits (3,905) (3,905)
Deferred Property Taxes (9,560) (8,063)
Mark-to-Market Energy Trading and Derivative Contracts (4,613) (7,198)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (258,663) 9,894
Fuel, Materials and Supplies (6,214) (15,861)
Fuel Recovery 12,552 116,473
Accounts Payable (16,306) (30,223)
Taxes Accrued 61,198 164,131
Change in Other Assets (61,836) 722
Change in Other Liabilities 19,093 10,733
--------- ---------
Net Cash Flows From Operating Activities 33,501 486,683
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (97,952) (158,191)
Other - (354)
--------- ---------
Net Cash Flows Used For Investing Activities (97,952) (158,545)
--------- ----------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 797,335 -
Retirement of Long-term Debt (583,836) -
Reacquisition of Trust Preferred Securities - (12,471)
Change in Short-term Debt Affiliated (net) 200,000 -
Retirement of Common Stock (386,004) -
Change in Advances from Affiliates (net) 198,371 (211,990)
Dividends Paid on Common Stock (115,505) (111,043)
Dividends Paid on Cumulative Preferred Stock (181) (181)
--------- ---------
Net Cash Flows From (Used For) Financing Activities 110,180 (335,685)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 45,729 (7,547)
Cash and Cash Equivalents at Beginning of Period 10,909 14,253
--------- ---------
Cash and Cash Equivalents at End of Period $ 56,638 $ 6,706
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $63,005,000 and
$80,612,000 and for income taxes was $44,322,000 and $11,939,000 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
THIRD QUARTER 2002 vs. THIRD QUARTER 2001
AND
YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001
CSPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 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
its 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.
Results of Operations
Net Income increased $11 million or 17% in the third quarter of 2002 due
to higher retail sales and reduced interest charges. Net Income increased $38
million or 30% in the year-to-date period due to reduced interest charges and a
$26 million extraordinary loss recorded in the prior period second quarter to
recognize a stranded asset resulting from deregulation.
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Electricity Marketing and Trading* $42 19 $ 45 7
Energy Delivery* 9 6 15 4
Sales to AEP Affiliates 2 17 (10) (20)
--- ----
Total $53 14 $ 50 5
=== ====
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The quarter and year-to-date increase in revenues is mainly due to
higher residential and commercial sales that resulted from above normal
temperatures during the third quarter compared with milder weather in 2001.
Changes in Operating Expenses
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Fuel $ 4 11 $ 4 3
Electricity Marketing Purchases 8 321 11 148
Purchases from AEP Affiliates 6 8 15 7
Other Operation 5 8 12 7
Maintenance - - (10) (18)
Depreciation and Amortization 1 3 3 4
Taxes other Than Income Taxes 1 2 (2) (2)
Income Taxes 16 50 16 22
--- ---
Total $41 14 $49 6
=== ===
Electricity Marketing Purchases increased in the quarter and year to
date periods due to increased purchases from third parties for resale to
wholesale customers and to meet internal demand.
Other Operation expense increased in both periods primarily due to
increases in benefits expense as a result of higher benefit costs and
application of a lower discount rate.
Maintenance expenses decreased in the year-to-date period of 2002 due to
boiler overhaul work that was performed during 2001. Expenses for maintaining
distribution overhead lines were also lower in 2002.
The increase in Income Taxes for both periods is predominately due to an
increase in pre-tax income.
Other Changes
The decrease in Nonoperating Income in both periods 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. Our 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. The decrease reflects a reduction in
electricity prices and margins due to a decrease in demand.
The decrease in Nonoperating Expense in the quarter and year-to-date was
due to lower energy trading overheads resulting from a decrease in trading
incentives.
Non-Operating Income Tax expense increased in both periods due to the
flow-through of deferred taxes and a change in the allocation of tax savings
from AEP.
The decrease in Interest in both periods 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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $262,754 $221,161 $ 670,830 $ 625,592
Energy Delivery 148,359 139,674 373,969 358,984
Sales to AEP Affiliates 17,324 14,856 42,277 52,547
-------- -------- ---------- ----------
TOTAL OPERATING REVENUES 428,437 375,691 1,087,076 1,037,123
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 47,228 42,702 135,942 132,100
Purchased Power:
Electricity Marketing 10,113 2,401 17,669 7,133
AEP Affiliates 85,228 79,263 235,432 220,039
Other Operation 62,394 57,856 178,042 165,941
Maintenance 14,878 15,254 44,068 53,763
Depreciation and Amortization 33,450 32,352 98,588 95,213
Taxes Other Than Income Taxes 37,570 36,686 97,176 99,452
Income Taxes 48,543 32,257 87,538 71,736
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES 339,404 298,771 894,455 845,377
-------- -------- ---------- ----------
OPERATING INCOME 89,033 76,920 192,621 191,746
NONOPERATING INCOME 5,361 10,153 19,751 31,457
NONOPERATING EXPENSES 1,015 4,182 1,432 16,182
NONOPERATING INCOME TAX EXPENSE 4,590 702 9,387 3,522
INTEREST CHARGES 12,672 16,871 39,857 53,092
-------- -------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 76,117 65,318 161,696 150,407
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION (INCLUSIVE OF TAX BENEFIT
OF $8,353,000) - - - (26,407)
-------- -------- ---------- ----------
NET INCOME 76,117 65,318 161,696 124,000
PREFERRED STOCK DIVIDEND REQUIREMENTS 694 244 1,078 847
-------- -------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 75,423 $ 65,074 $ 160,618 $ 123,153
======== ======== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $76,117 $65,318 $161,696 $124,000
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Power Hedges (1,123) - 326 -
------- ------- -------- --------
COMPREHENSIVE INCOME $74,994 $65,318 $162,022 $124,000
======= ======= ======== ========
The common stock of CSPCo 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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $217,290 $115,243 $176,103 $ 99,069
NET INCOME 76,117 65,318 161,696 124,000
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 21,766 20,738 65,300 62,214
Preferred Stock - 175 350 700
Capital Stock Expense 254 255 762 762
-------- -------- -------- --------
BALANCE AT END OF PERIOD $271,387 $159,393 $271,387 $159,393
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,582,400 $1,574,506
Transmission 412,188 401,405
Distribution 1,193,010 1,159,105
General 152,771 146,732
Construction Work in Progress 86,262 72,572
---------- ----------
Total Electric Utility Plant 3,426,631 3,354,320
Accumulated Depreciation and Amortization 1,446,071 1,377,032
---------- ----------
NET ELECTRIC UTILITY PLANT 1,980,560 1,977,288
---------- ----------
OTHER PROPERTY AND INVESTMENTS 38,632 40,369
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 233,662 193,915
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 7,548 12,358
Advances to Affiliates 25,117 -
Accounts Receivable:
Customers 34,437 41,770
Affiliated Companies 100,664 63,470
Miscellaneous 20,669 16,968
Allowance for Uncollectible Accounts (778) (745)
Fuel - at average cost 20,561 20,019
Materials and Supplies - at average cost 40,833 38,984
Accrued Utility Revenues 22,012 7,087
Energy Trading and Derivative Contracts 319,191 347,198
Prepayments and Other Current Assets 35,724 28,733
---------- ----------
TOTAL CURRENT ASSETS 625,978 575,842
---------- ----------
REGULATORY ASSETS 251,896 262,267
---------- ----------
DEFERRED CHARGES 34,361 56,187
---------- ----------
TOTAL ASSETS $3,165,089 $3,105,868
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 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 575,131 574,369
Accumulated Other Comprehensive Income 326 -
Retained Earnings 271,387 176,103
---------- ----------
Total Common Shareowner's Equity 887,870 791,498
Cumulative Preferred Stock - Subject to
Mandatory Redemption - 10,000
Long-term Debt 583,565 571,348
---------- ----------
TOTAL CAPITALIZATION 1,471,435 1,372,846
---------- ----------
OTHER NONCURRENT LIABILITIES 34,560 36,715
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General 58,500 20,500
Long-term Debt Due Within One Year -
Affiliated Companies - 200,000
Short-term Debt Affiliated 290,000 -
Advances from Affiliates - 181,384
Accounts Payable - General 77,701 60,689
Accounts Payable - Affiliated Companies 56,179 83,697
Taxes Accrued 121,961 116,364
Interest Accrued 12,392 10,907
Energy Trading and Derivative Contracts 299,439 334,957
Other 41,769 36,305
---------- ----------
TOTAL CURRENT LIABILITIES 957,941 1,044,803
---------- ----------
DEFERRED INCOME TAXES 454,900 443,722
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 34,841 37,176
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 183,429 157,706
---------- ----------
DEFERRED CREDITS 27,983 12,900
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $3,165,089 $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)
Nine Months Ended September 30,
(in thousands)
2002 2001
---- ----
OPERATING ACTIVITIES:
Net Income $ 161,696 $ 124,000
Adjustments for Noncash Items:
Depreciation and Amortization 98,666 96,194
Deferred Income Taxes 12,450 25,360
Deferred Investment Tax Credits (2,335) (2,508)
Deferred Property Tax 31,968 53,168
Mark-to-Market Energy Trading and Derivative Contracts (21,033) (60,743)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (33,529) (3,254)
Fuel, Materials and Supplies (2,391) (8,977)
Accrued Utility Revenues (14,925) 5,129
Prepayments and Other Current Assets (6,991) 400
Accounts Payable (10,506) 6,848
Taxes Accrued 5,597 (28,836)
Other Assets (3,155) 13,437
Other Liabilities 12,218 (27,045)
--------- ---------
Net Cash Flows From Operating Activities 227,730 193,173
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (88,101) (110,631)
Proceeds from Sale of Property 730 10,673
--------- ---------
Net Cash Flows Used For Investing Activities (87,371) (99,958)
--------- ---------
FINANCING ACTIVITIES:
Proceeds From Issuance of Long-term Debt - Affiliated - 200,000
Retirement of Long-term Debt-Affiliated (200,000) -
Change in Short-term Debt Affiliated (net) 290,000 -
Issuance of Long-term Debt 160,000 -
Changes In Advances from Affiliates (net) (206,501) 51,422
Retirement of Cumulative Preferred Stock (10,000) (5,000)
Retirement of Long-term Debt (112,843) (280,632)
Dividends Paid on Common Stock (65,300) (62,214)
Dividends Paid on Cumulative Preferred Stock (525) (788)
--------- ---------
Net Cash Flows Used For Financing Activities (145,169) (97,212)
--------- ---------
Net Decrease in Cash and Cash Equivalents (4,810) (3,997)
Cash and Cash Equivalents at Beginning of Period 12,358 11,600
--------- ---------
Cash and Cash Equivalents at End of Period $ 7,548 $ 7,603
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $37,204,000 and
$49,126,000 and for income taxes was $32,254,000 and $17,579,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $1,019,000 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
THIRD QUARTER 2002 vs. THIRD 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 approximately 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
utility systems and power marketers including power trading transactions. I&M
also sells wholesale power to municipalities and electric cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among
its 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.
Under the terms of unit power agreements, I&M purchases 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.
Results of Operations
The $10 million or 41% increase in Net Income for the third quarter
reflects increased sales of electricity to retail customers and a decrease in
Other Operation expense. Net Income decreased $31 million or 36% in the
year-to-date period due primarily to a reduction in generation in 2002 as a
result of a refueling outage at each unit of I&M's Cook Plant and maintenance
outages at Rockport Plant.
Operating revenues increased 6% in the third quarter reflecting
increased sales to retail customers and AEP affiliates. The 2% decrease in
operating revenues for the year-to-date period reflects the decrease in
generation in 2002 due to power plant outages.
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Electricity Marketing and Trading* $ 10 4 $ 8 1
Energy Delivery* 5 5 1 N.M.
Sales to AEP Affiliates 8 16 (34) (18)
--- ----
Total $23 6 $(25) (2)
=== ====
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The increase in Electricity Marketing and Trading revenues in the third
quarter and year-to-date was due to increased sales to I&M's retail customers
due to warmer summer weather partially offset by lower wholesale energy prices.
The increase in Sales to AEP Affiliates in the third quarter reflects increased
generation from Cook Plant in 2002. In September 2001 problems with the water
intake system forced Cook Plant into an unplanned outage. Revenues from Sales to
AEP Affiliates in the year-to-date period decreased significantly reflecting
less power being available for sale as each of the Cook Nuclear Plant units was
shutdown for refueling in the first six months of 2002 and both units of
Rockport Plant underwent scheduled planned boiler maintenance in the first
quarter of 2002. With the outages in 2002, I&M's available generation decreased
resulting in less power being delivered to the AEP Power Pool.
Changes in Operating Expenses
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Fuel $ 6 11 $(11) (6)
Electricity Marketing Purchases 9 173 11 81
Purchases from AEP Affiliates (3) (5) (6) (3)
Other Operation (14) (11) 12 4
Maintenance 10 31 21 23
Depreciation and Amortization 1 2 3 3
Taxes other Than Income Taxes - - 1 2
Income Taxes 1 7 (20) (39)
--- ----
Total $10 3 $ 11 1
=== ====
The increase in Fuel expense for the third quarter reflects an increase
in nuclear and fossil fuel costs as generation rose significantly in 2002. Fuel
expense for the year-to-date period decreased primarily due to the decrease in
generation reflecting the plant outages as both units of the nuclear plant were
refueled in 2002 and Rockport Plant's outage time increased. In addition, gains
on coal trading lowered the average fuel cost.
The increase in Electricity Marketing Purchases in both periods is due
to increased purchases from third parties for sales for resale and to meet
internal demand.
Purchases from AEP Affiliates decreased in both periods due to lower
purchase volumes and lower cost of power acquired from AEGCo and the AEP Power
Pool.
For the third quarter, Other Operation expense decreased due to lower
trading incentives, the effect of recording severances in 2001 for energy
delivery employees, and lower nuclear operations costs reflecting the effects of
the 2001 outage at Cook Plant. Other Operation and Maintenance expenses
increased for the year-to-date period due to costs related to the nuclear plant
refueling outages. The increase in Maintenance expense for the third quarter
reflects amortization of deferred refueling expenses.
The decrease in Income Tax expense attributable to operations for the
year-to-date period is due primarily to a decline in pre-tax operating income.
Other Changes
Nonoperating Income decreased in the quarter and year-to-date periods
due to a reduction in power trading margins outside of AEP's traditional
marketing area resulting from the overall decline of wholesale energy markets.
Nonoperating Expenses decreased due to reductions in variable compensation
expense associated with wholesale trading. Nonoperating
Income Taxes decreased in the year-to-date period due to a decrease in
pre-tax income.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $271,733 $261,666 $ 747,207 $ 739,377
Energy Delivery 89,222 84,674 242,416 241,581
Sales to AEP Affiliates 60,517 52,117 153,127 187,546
-------- -------- ---------- ----------
TOTAL OPERATING REVENUES 421,472 398,457 1,142,750 1,168,504
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 65,904 59,535 173,223 183,999
Purchased Power:
Electricity Marketing 13,764 5,036 24,444 13,476
AEP Affiliates 59,846 62,730 176,463 182,083
Other Operation 108,457 122,211 340,556 328,654
Maintenance 41,668 31,913 112,291 91,594
Depreciation and Amortization 42,081 41,172 125,817 122,735
Taxes Other Than Income Taxes 16,698 16,376 52,794 51,950
Income Taxes 16,050 14,975 29,930 49,466
-------- -------- ---------- ---------
TOTAL OPERATING EXPENSES 364,468 353,948 1,035,518 1,023,957
-------- -------- ---------- ----------
OPERATING INCOME 57,004 44,509 107,232 144,547
NONOPERATING INCOME 22,614 25,463 71,878 82,181
NONOPERATING EXPENSES 17,590 20,030 50,711 63,759
NONOPERATING INCOME TAXES 2,999 2,113 3,887 6,246
INTEREST CHARGES 23,717 22,765 70,648 71,922
-------- -------- ---------- ----------
NET INCOME 35,312 25,064 53,864 84,801
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,145 1,155 3,453 3,466
-------- -------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 34,167 $ 23,909 $ 50,411 $ 81,335
======== ======== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $35,312 $25,064 $53,864 $84,801
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge 1,348 (878) 3,835 (3,700)
Cash Flow Power Hedges (1,218) - 349 -
------- ------- ------- -------
COMPREHENSIVE INCOME $35,442 $24,186 $58,048 $81,101
======= ======= ======= =======
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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 90,847 $60,869 $ 74,605 $ 3,443
NET INCOME 35,312 25,064 53,864 84,801
DEDUCTIONS:
Cash Dividends Declared -
Cumulative Preferred Stock 1,109 1,121 3,352 3,365
Capital Stock Expense 33 34 100 101
-------- ------- -------- -------
BALANCE AT END OF PERIOD $125,017 $84,778 $125,017 $84,778
======== ======= ======== =======
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,768,964 $2,758,160
Transmission 970,724 957,336
Distribution 914,575 900,921
General (including nuclear fuel) 222,247 233,005
Construction Work in Progress 116,000 74,299
---------- ----------
Total Electric Utility Plant 4,992,510 4,923,721
Accumulated Depreciation and Amortization 2,541,379 2,436,972
---------- ----------
NET ELECTRIC UTILITY PLANT 2,451,131 2,486,749
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS 832,585 834,109
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 257,142 215,544
---------- ----------
OTHER PROPERTY AND INVESTMENTS 123,674 127,977
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 9,002 16,804
Advances to Affiliates 45,095 46,309
Accounts Receivable:
Customers 54,781 60,864
Affiliated Companies 143,331 31,908
Miscellaneous 35,093 25,398
Allowance for Uncollectible Accounts (749) (741)
Fuel - at average cost 23,736 28,989
Materials and Supplies - at average cost 95,538 91,440
Energy Trading and Derivative Contracts 367,452 399,195
Accrued Utility Revenues 6,484 2,072
Prepayments 10,256 6,497
---------- ----------
TOTAL CURRENT ASSETS 790,019 708,735
---------- ----------
REGULATORY ASSETS 376,141 408,927
---------- ----------
DEFERRED CHARGES 40,464 34,967
---------- ----------
TOTAL ASSETS $4,871,156 $4,817,008
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 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 858,526 733,216
Accumulated Other Comprehensive Income (Loss) 349 (3,835)
Retained Earnings 125,017 74,605
---------- ----------
Total Common Shareowner's Equity 1,040,476 860,570
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,103 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,365,815 1,312,082
---------- ----------
TOTAL CAPITALIZATION 2,479,339 2,246,333
---------- ----------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 583,764 600,244
Other 83,265 87,025
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES 667,029 687,269
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 90,000 340,000
Accounts Payable:
General 109,693 86,766
Affiliated Companies 100,429 43,956
Taxes Accrued 84,495 69,761
Interest Accrued 25,162 20,691
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Energy Trading and Derivative Contracts 341,346 383,714
Other 86,024 82,363
---------- ----------
TOTAL CURRENT LIABILITIES 860,576 1,032,214
---------- ----------
DEFERRED INCOME TAXES 381,319 400,531
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 99,915 105,449
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK
- ROCKPORT PLANT UNIT 2 74,812 77,592
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 206,527 175,581
---------- ----------
DEFERRED CREDITS 101,639 92,039
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $4,871,156 $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)
Nine Months Ended September 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 53,864 $ 84,801
Adjustments for Noncash Items:
Depreciation and Amortization 125,881 124,993
Deferral of Incremental Nuclear
Refueling Outage Expenses (net) (38,103) (224)
Unrecovered Fuel and Purchased Power Costs 28,126 28,126
Amortization of Nuclear Outage Costs 30,000 30,000
Deferred Income Taxes (6,885) (6,517)
Deferred Investment Tax Credits (5,534) (5,604)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (115,027) 34,908
Fuel, Materials and Supplies 1,155 (16,416)
Accrued Utility Revenues (4,412) -
Accounts Payable 79,400 (61,519)
Taxes Accrued 14,734 47,780
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Mark-to-Market Energy Trading and Derivative Contracts (20,358) (91,699)
Regulatory Liability - Trading Gains 8,847 25,938
Regulatory Assets - Trading Losses (4,105) 13,102
Change in Other Assets 7,526 19,286
Change in Other Liabilities (12,113) 11,997
--------- ---------
Net Cash Flows From Operating Activities 161,460 257,416
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (92,387) (65,312)
Buyout of Nuclear Fuel Leases - (92,616)
Other 1,027 524
--------- ---------
Net Cash Flows Used For Investing Activities (91,360) (157,404)
--------- ---------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 125,000 -
Issuance of Long-term Debt 49,648 -
Retirement of Cumulative Preferred Stock (424) -
Retirement of Long-term Debt (250,000) (44,922)
Change in Advances from Affiliates (net) 1,214 (39,162)
Dividends Paid on Cumulative Preferred Stock (3,340) (3,365)
--------- ---------
Net Cash Flows Used For Financing Activities (77,902) (87,449)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (7,802) 12,563
Cash and Cash Equivalents at Beginning of Period 16,804 14,835
--------- ---------
Cash and Cash Equivalents at End of Period $ 9,002 $ 27,398
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $63,987,000 and
$67,657,000 and for income taxes was $21,225,000 and $13,079,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $1,023,000 in
2001.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2002 vs. THIRD 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 173,000 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
its 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.
Results of Operations
Net Income increased approximately $1 million or 13% in the third
quarter and $6 million or 42% in the year-to-date period primarily due to
reduced capacity charges and increased transmission equalization credits
resulting from the decrease in MLR. Increased retail sales due to warmer summer
weather also contributed to the increase in Net Income.
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Electricity Marketing and Trading* $ 5 9 $13 9
Energy Delivery* - - - -
Sales to AEP Affiliates (1) (8) (7) (22)
--- ---
Total $ 4 4 $ 6 2
=== ===
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The increase in revenues in the third quarter is due primarily to
increased sales to retail customers reflecting warmer summer weather and
increased fuel recovery revenues. This was partly offset by lower Sales to AEP
Affiliates in both periods because of planned outages in 2002. KPCo's generation
decreased resulting in less power being delivered to the AEP Power Pool.
Changes in Operating Expenses
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Fuel $ 2 12 $ 6 12
Electricity Marketing Purchases 3 N.M. 3 N.M.
Purchases from AEP Affiliates 1 1 (6) (7)
Other Operation (2) (15) (5) (12)
Maintenance 1 20 3 19
Taxes Other Than Income Taxes - - 1 10
Income Taxes 1 36 2 21
--- ---
Total Operating Expenses $ 6 7 $ 4 1
=== ===
N.M. = Not Meaningful
Fuel expense increased in both periods as a result of increases in the
cost of coal and decreases in credits to Fuel expense. Under the Kentucky
commission's fuel clause mechanism, a portion of the profits on wholesale power
trading transactions are shared with the retail customers. This sharing is
recognized through credits to Fuel expense that match the increased retail
revenues. As margins on wholesale electricity marketing and trading transactions
declined, the amount of credits shared through the fuel clause adjustment
mechanism decreased.
Third quarter Electricity Marketing Purchases expense increased compared
to prior year due to increased purchases from third parties for resale to
wholesale customers and to meet internal demand. Year-to-date Purchases from AEP
Affiliates declined due to a decrease in capacity charges from the AEP Power
Pool as KPCo's MLR declined. Also contributing to the year-to-date decline were
fewer purchases and lower prices on power purchased from AEGCo.
Other Operation expense decreased for both periods due to reduced
consumption of emission allowances, reduced accruals for trading incentive
compensation and increased AEP transmission equalization credits. Under the AEP
Transmission Equalization Agreement, KPCo and certain eastern region affiliates
share the costs associated with the ownership of their transmission system based
upon each company's 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 in both periods primarily as a result of
planned power plant outages.
Taxes Other Than Income Taxes increased year-to-date primarily due to
increases in real and personal property taxes.
Income Taxes year-to-date and quarter-to-date have increased primarily as a
result of increases in pre-tax income.
Other Changes
Year-to-date Nonoperating Income decreased as a result of decreased
margins on power trading activity outside of the AEP System's traditional
marketing area resulting from soft market demand. Nonoperating Expenses
decreased quarter and year-to-date as a result of decreases in trading
incentives.
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $ 55,645 $ 51,079 $165,565 $ 152,396
Energy Delivery 34,623 34,203 101,137 101,367
Sales to AEP Affiliates 10,091 10,915 25,006 31,942
-------- -------- -------- ----------
TOTAL OPERATING REVENUES 100,359 96,197 291,708 285,705
-------- -------- -------- ----------
OPERATING EXPENSES:
Fuel 19,747 17,581 59,084 52,955
Purchased Power:
Electricity Marketing 2,572 - 2,574 38
AEP Affiliates 31,440 31,037 92,747 99,197
Other Operation 12,932 15,172 37,902 43,170
Maintenance 7,168 5,984 19,795 16,598
Depreciation and Amortization 8,330 8,163 24,856 24,270
Taxes Other Than Income Taxes 1,904 1,877 6,407 5,826
Income Taxes 5,147 3,796 12,190 10,096
-------- -------- -------- ----------
TOTAL OPERATING EXPENSES 89,240 83,610 255,555 252,150
-------- -------- -------- ----------
OPERATING INCOME 11,119 12,587 36,153 33,555
NONOPERATING INCOME 1,712 1,227 6,907 10,670
NONOPERATING EXPENSES 707 1,754 701 7,057
NONOPERATING INCOME TAX EXPENSE (CREDIT) (801) (201) 929 1,221
INTEREST CHARGES 6,931 6,949 19,944 20,818
-------- -------- -------- ----------
NET INCOME $ 5,994 $ 5,312 $ 21,486 $ 15,129
======== ======== ======== ==========
STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $5,994 $5,312 $21,486 $15,129
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Power Hedges (447) - 125 -
Cash Flow Interest Rate Hedges 521 (618) 1,394 (2,040)
------ ------ ------- -------
COMPREHENSIVE INCOME $6,068 $4,694 $23,005 $13,089
====== ====== ======= =======
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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $50,237 $52,208 $48,833 $57,513
NET INCOME 5,994 5,312 21,486 15,129
DEDUCTIONS:
Cash Dividends Declared 7,044 7,561 21,132 22,683
------- ------- ------- -------
BALANCE AT END OF PERIOD $49,187 $49,959 $49,187 $49,959
======= ======= ======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 274,781 $ 271,070
Transmission 371,904 374,116
Distribution 408,272 402,537
General 62,768 65,059
Construction Work in Progress 103,617 15,633
---------- ----------
Total Electric Utility Plant 1,221,342 1,128,415
Accumulated Depreciation and Amortization 399,412 384,104
---------- ----------
NET ELECTRIC UTILITY PLANT 821,930 744,311
---------- ----------
OTHER PROPERTY AND INVESTMENTS 7,107 6,492
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 89,701 77,972
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 873 1,947
Accounts Receivable:
Customers 17,620 20,036
Affiliated Companies 32,731 16,012
Miscellaneous 2,562 3,333
Allowance for Uncollectible Accounts (237) (264)
Fuel - at average cost 9,829 12,060
Materials and Supplies - at average cost 17,513 15,766
Accrued Utility Revenues 6,777 5,395
Energy Trading and Derivative Contracts 122,674 139,605
Prepayments 2,078 1,314
---------- ----------
TOTAL CURRENT ASSETS 212,420 215,204
---------- ----------
REGULATORY ASSETS 98,925 97,692
---------- ----------
DEFERRED CHARGES 8,821 11,572
---------- ----------
TOTAL ASSETS $1,238,904 $1,153,243
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
September 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) (384) (1,903)
Retained Earnings 49,187 48,833
---------- ----------
Total Common Shareowner's Equity 258,003 256,130
Long-term Debt 300,915 251,093
---------- ----------
TOTAL CAPITALIZATION 558,918 507,223
---------- ----------
OTHER NONCURRENT LIABILITIES 12,422 11,929
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General 70,000 95,000
Long-term Debt Due Within One Year -
Affiliated Companies 15,000 -
Advances from Affiliates 92,591 66,200
Accounts Payable:
General 30,974 23,464
Affiliated Companies 35,762 22,557
Customer Deposits 8,226 4,461
Taxes Accrued 6,945 10,305
Interest Accrued 5,376 5,269
Energy Trading and Derivative Contracts 115,735 144,364
Other 15,795 12,882
---------- ----------
TOTAL CURRENT LIABILITIES 396,404 384,502
---------- ----------
DEFERRED INCOME TAXES 176,311 168,304
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 9,519 10,405
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 70,417 63,412
---------- ----------
DEFERRED CREDITS 14,913 7,468
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $1,238,904 $1,153,243
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended September 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 21,486 $ 15,129
Adjustments for Noncash Items:
Depreciation and Amortization 24,856 24,270
Deferred Income Taxes 7,461 9,644
Deferred Investment Tax Credits (886) (889)
Amortization of Deferred Property Taxes 4,472 4,299
Deferred Fuel Costs (net) 2,081 (2,708)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (13,559) 15,278
Fuel, Materials and Supplies 484 (3,251)
Accrued Utility Revenues (1,382) 4,285
Accounts Payable 20,715 (14,438)
Taxes Accrued (3,360) (4,483)
Mark-to-Market Energy and Derivative Contracts (13,161) (25,113)
Change in Other Assets (6,626) (6,772)
Change in Other Liabilities 12,238 1,113
--------- --------
Net Cash Flows From Operating Activities 54,819 16,364
--------- --------
INVESTING ACTIVITIES:
Construction Expenditures (100,677) (26,628)
Proceeds from Sales of Property 182 216
--------- --------
Net Cash Flow Used For Investing Activities (100,495) (26,412)
--------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - Affiliated Company 123,843 75,000
Retirement of Long-term Debt (84,500) (60,000)
Change in Advances from Affiliates (net) 26,391 16,610
Dividends Paid (21,132) (22,683)
--------- --------
Net Cash Flows From Financing Activities 44,602 8,927
--------- --------
Net Decrease in Cash and Cash Equivalents (1,074) (1,121)
Cash and Cash Equivalents at Beginning of Period 1,947 2,270
--------- --------
Cash and Cash Equivalents at End of Period $ 873 $ 1,149
========= ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $19,560,000 and
$18,899,000 and for income taxes was $7,025,000 and $6,011,000 in 2002 and 2001,
respectively. Noncash acquisitions under capital leases were $22,021 and
$817,000 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
THIRD QUARTER 2002 vs. THIRD 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 utility systems and power
marketers including power trading transactions. OPCo also sells wholesale power
to municipalities and electric cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among
its 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.
Results of Operations
Net Income increased $29 million or 56% in the third quarter of 2002
primarily due to increased sales to residential and commercial customers.
Year-to-date Net Income increased $84 million or 73% due to the effect of an
extraordinary loss recorded in the second quarter of 2001 to recognize a
stranded asset resulting from deregulation, and decreases in fuel and
maintenance expenses.
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing and Trading* $ 27 10 $ 20 3
Energy Delivery* 22 16 42 10
Sales to AEP Affiliates (18) (14) (54) (13)
---- ----
Total $ 31 6 $ 8 1
==== ====
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The increase in revenues is mainly attributable to increased residential
and commercial sales during the third quarter due to warmer weather. The
decrease in revenues from Sales to AEP Affiliates was mainly attributable to a
decrease in the price of power delivered to the AEP Power Pool.
Changes in Operating Expenses
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $(19) (11) $(108) (20)
Electricity Marketing Purchases 10 63 11 24
Purchases from AEP Affiliates 6 45 8 16
Other Operation (8) (8) 4 1
Maintenance (2) (5) (15) (14)
Depreciation and Amortization 3 5 9 5
Taxes Other Than Income Taxes (4) (7) 1 -
Income Taxes 17 73 38 52
---- -----
Total $ 3 1 $ (52) (4)
==== =====
The Fuel expense decrease for the quarter and year-to-date reflect a
year-to-date reduction of 22% in the average cost of fuel for generation offset
in part by a 2% year-to-date increase in MWH generated. The decrease in fuel
costs are the result of purchasing coal at lower prices on the open market in
2002.
Electricity Marketing Purchases increased for the quarter and
year-to-date due to increased purchases from third parties for resale to
wholesale customers and to meet internal demand.
Other Operation expense decreased for the quarter due to lower COLI
expense caused by mid-year cash surrender value adjustments. The year-to-date
increase in Other Operation expense was due to higher current year benefit
expense caused by increased benefit costs and a lower discount rate utilized to
determine OPEB and pension expense offsetting the quarter's COLI expense
reduction.
Maintenance expenses decreased in the third 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 increase in
depreciation expense from the placement of additional plant into service at the
Gavin Plant in 2001.
The decrease in Taxes Other Than Income Taxes during the third quarter
is due to a reduction in tax rates on generation property.
The increase in Income Taxes for both periods is predominately due to an
increase in pre-tax income due to the replacement of higher priced affiliated
coal purchases with nonaffiliated coal purchases.
Other Changes
Nonoperating Income decreased in the third quarter due to the decreases
in power trading margins from AEP Power Pool trading transactions outside of the
AEP's Systems 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. On a year-to-date basis
Nonoperating Income decreased due to lower power trading margins and the loss of
the 2001 interest income from the coal subsidiary deposits. The coal
subsidiaries were sold in July 2001.
Nonoperating Expenses decreased during both periods due to reductions in
variable incentive compensation expenses associated with wholesale trading.
The increase in Nonoperating Income Tax Expense results from the prior
period sale of the Ohio Coal companies in the third quarter 2001.
The decrease in Interest Charges was primarily due to a decrease in the
outstanding balances of long-term debt 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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $290,890 $263,952 $ 812,976 $ 792,897
Energy Delivery 162,200 140,343 447,104 405,352
Sales to AEP Affiliates 113,276 131,240 348,303 401,985
-------- -------- ---------- ----------
TOTAL OPERATING REVENUES 566,366 535,535 1,608,383 1,600,234
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 148,480 167,155 439,913 547,773
Purchased Power:
Electricity Marketing 24,575 15,094 57,834 46,741
AEP Affiliates 20,375 14,098 54,867 47,337
Other Operation 94,951 103,300 290,982 286,861
Maintenance 32,011 33,786 90,956 105,634
Depreciation and Amortization 62,144 59,267 185,941 176,992
Taxes Other Than Income Taxes 46,341 49,914 135,472 134,812
Income Taxes 40,279 23,253 110,446 72,593
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES 469,156 465,867 1,366,411 1,418,743
-------- -------- ---------- ----------
OPERATING INCOME 97,210 69,668 241,972 181,491
NONOPERATING INCOME 11,157 15,507 43,057 66,245
NONOPERATING EXPENSES 6,241 15,882 17,501 43,706
NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,638 (7,163) 7,986 (3,166)
INTEREST CHARGES 18,230 25,078 59,885 70,327
-------- -------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 80,258 51,378 199,657 136,869
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION (INCLUSIVE OF TAX BENEFIT
OF $11,585,000) - - - (21,515)
-------- -------- -------- ----------
NET INCOME 80,258 51,378 199,657 115,354
PREFERRED STOCK DIVIDEND REQUIREMENTS 315 315 944 944
-------- -------- -------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 79,943 $ 51,063 $198,713 $ 114,410
======== ======== ======== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $80,258 $51,378 $199,657 $115,354
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedges - 345 (190) 20
Cash Flow Power Hedges (1,527) - 432 -
------- ------- -------- --------
COMPREHENSIVE INCOME $78,731 $51,723 $199,899 $115,374
======= ======= ======== ========
The common stock of OPCo 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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $454,903 $389,945 $401,297 $398,086
NET INCOME 80,258 51,378 199,657 115,354
CASH DIVIDENDS DECLARED:
Common Stock 32,582 35,744 97,746 107,232
Cumulative Preferred Stock 315 315 944 944
-------- -------- -------- --------
BALANCE AT END OF PERIOD $502,264 $405,264 $502,264 $405,264
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $3,035,181 $3,007,866
Transmission 910,102 891,283
Distribution 1,103,381 1,081,122
General 237,077 245,232
Construction Work in Progress 286,089 165,073
---------- ----------
Total Electric Utility Plant 5,571,830 5,390,576
Accumulated Depreciation and Amortization 2,545,585 2,452,571
---------- ----------
NET ELECTRIC UTILITY PLANT 3,026,245 2,938,005
---------- ----------
OTHER PROPERTY AND INVESTMENTS 67,327 62,303
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 311,812 263,734
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 7,952 8,848
Accounts Receivable:
Customers 83,018 84,694
Affiliated Companies 141,694 148,563
Miscellaneous 13,841 20,409
Allowance for Uncollectible Accounts (555) (1,379)
Fuel - at average cost 79,909 84,724
Materials and Supplies - at average cost 83,250 88,768
Accrued Utility Revenues 2,677 -
Energy Trading and Derivative Contracts 430,583 472,246
Prepayments and Other 32,195 20,865
---------- ----------
TOTAL CURRENT ASSETS 874,564 927,738
---------- ----------
REGULATORY ASSETS 599,352 644,625
---------- ----------
DEFERRED CHARGES 41,903 79,662
---------- ----------
TOTAL ASSETS $4,921,203 $4,916,067
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 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) 46 (196)
Retained Earnings 502,264 401,297
---------- ----------
Total Common Shareholder's Equity 1,285,994 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 977,327 1,203,841
---------- ----------
TOTAL CAPITALIZATION 2,288,819 2,414,124
---------- ----------
OTHER NONCURRENT LIABILITIES 123,853 130,386
---------- ----------
CURRENT LIABILITIES:
Short-term Debt From Affiliated Companies 150,000 -
Long-term Debt Due Within One Year - General 29,850 -
Long-term Debt Due Within One Year -
Affiliated Companies 60,000 -
Advances from Affiliates 160,682 300,213
Accounts Payable - General 139,852 131,057
Accounts Payable - Affiliated Companies 187,736 176,520
Customer Deposits 14,553 5,452
Taxes Accrued 164,140 126,770
Interest Accrued 19,549 17,679
Obligations Under Capital Leases 13,925 16,405
Energy Trading and Derivative Contracts 397,546 456,047
Other 82,007 90,431
---------- ----------
TOTAL CURRENT LIABILITIES 1,419,840 1,320,574
---------- ----------
DEFERRED INCOME TAXES 798,735 797,889
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 19,630 21,925
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 243,410 214,487
---------- ----------
DEFERRED CREDITS 26,916 16,682
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $4,921,203 $4,916,067
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended September 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 199,657 $ 115,354
Adjustments for Noncash Items:
Depreciation 130,120 134,105
Amortization of Transition Assets 55,820 55,029
Deferred Income Taxes 95 182,166
Amortization of Deferred Property Taxes 45,275 61,821
Extraordinary Loss - Discontinuance SFAS 71 - 21,515
Accumulated Provisions - Noncurrent 3,543 (390,313)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 14,289 43,127
Fuel, Materials and Supplies 10,333 17,611
Accrued Utility Revenues (2,677) 264
Prepayments and Other (11,330) (13,774)
Accounts Payable 20,011 (69,673)
Customer Deposits 9,101 (30,743)
Taxes Accrued 37,370 (197,225)
Interest Accrued 1,870 9,596
Energy Trading Contract (net) (34,477) (82,190)
Other Operating Assets (18,512) 47,372
Other Operating Liabilities (14,350) (92,745)
--------- ---------
Net Cash Flows From (Used For) Operating Activities 446,138 (188,703)
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (224,257) (242,898)
Proceeds from Sale of Property and Other 5,444 16,562
Investment in Coal Companies - (32,115)
--------- ---------
Net Cash Flows Used For Investing Activities (218,813) (258,451)
--------- ---------
FINANCING ACTIVITIES:
Change in Short-term Debt Affiliated (net) 150,000 -
Issuance of Long-term Debt - Affiliated - 300,000
Change in Advances to Affiliates (net) (139,531) 452,534
Retirement of Long-term Debt (140,000) (216,697)
Dividends Paid on Common Stock (97,746) (107,232)
Dividends Paid on Cumulative Preferred Stock (944) (944)
--------- ---------
Net Cash Flows From (Used For) Financing Activities (228,221) 427,661
--------- ---------
Net Decrease in Cash and Cash Equivalents (896) (19,493)
Cash and Cash Equivalents at Beginning of Period 8,848 31,393
--------- ---------
Cash and Cash Equivalents at End of Period $ 7,952 $ 11,900
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $56,864,000 and
$59,492,000 and for income taxes was $29,981,000 and $55,806,000 in 2002 and
2001, respectively. Noncash acquisitions under capital leases were $98,000 and
$595,000 in 2002 and 2001, respectively.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2002 vs. THIRD 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.
Results of Operations
Net Income decreased by $10 million or 20% for the quarter and $10
million or 17% for the year-to-date period. The decreases primarily resulted
from reduced wholesale margins due to a decline in demand for electricity
resulting from mild weather and a slow economic recovery.
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
- -
Electricity Marketing and Trading* $(75) (34) $(260) (45)
Energy Delivery* (7) (7) 6 3
Sales to AEP Affiliates (13) (198) (24) (94)
---- -----
Total $(95) (29) $(278) (34)
==== =====
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
Operating revenues decreased during the quarter and for the
year-to-date periods as a result of a decline in fuel recovery revenue.
Additionally, the quarterly results were impacted by decreases due to the ICR
adjustments (see Note 6), decreases in usage by existing customers and decreases
in growth in the number of customers resulting from the slowing economy. The
Sales to AEP Affiliates revenue is negative for the quarter due to the impact of
the ICR adjustments (see Note 6).
Changes in Operating Expenses
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Fuel $(96) (62) $(262) (64)
Electricity Marketing (1) (21) (29) (133)
Purchases from AEP Affiliates 15 N.M. 27 67
Other Operation - - (7) (7)
Maintenance (1) (8) 3 7
Depreciation and Amortization 2 11 5 8
Taxes Other Than Income Taxes 2 25 2 11
Income Taxes (7) (23) (7) (18)
---- -----
Total $(86) (32) $(268) (37)
==== =====
N.M. = Not Meaningful
The decrease in Fuel expense for both the quarter and year-to-date was
primarily due to the amortization of previously overrecovered fuel costs, lower
market prices for natural gas and fuel oil and deferral of newly underrecovered
fuel costs due to the ICR adjustments through the fuel clause recovery mechanism
(see Note 6).
The decrease in the quarter and year-to-date Electricity Marketing expense
resulted mainly from a decrease in energy prices and the ICR adjustments (see
Note 6).
The increase in the quarter and year-to-date in Purchases from AEP
Affiliates results mainly from the availability of internal generation and the
ICR adjustments (see Note 6).
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 third quarter due primarily to lower
production 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
primarily due to the additional depreciable capitalized costs involved in
repowering Northeast Station Units 1 & 2 completed in 2001.
Taxes Other Than Income Taxes increased in the quarter and year-to-date
primarily due to the increase in ad valorem taxes.
Income Taxes decreased in the quarter and year-to-date periods primarily
due to a decrease in pre-tax income.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $144,647 $219,429 $321,160 $581,450
Energy Delivery 92,077 99,200 214,624 208,911
Sales to AEP Affiliates (6,626) 6,744 1,630 25,451
-------- -------- -------- --------
TOTAL OPERATING REVENUES 230,098 325,373 537,414 815,812
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 58,410 154,177 150,279 411,905
Purchased Power:
Electricity Marketing 2,430 3,069 (7,230) 22,005
AEP Affiliates 20,640 5,985 67,238 40,256
Other Operation 31,957 32,438 92,845 100,033
Maintenance 10,024 10,886 36,079 33,575
Depreciation and Amortization 22,496 20,313 64,473 59,458
Taxes Other Than Income Taxes 9,278 7,394 25,209 22,720
Income Taxes 24,153 31,197 29,200 35,665
-------- -------- -------- --------
TOTAL OPERATING EXPENSES 179,388 265,459 458,093 725,617
-------- -------- -------- --------
OPERATING INCOME 50,710 59,914 79,321 90,195
NONOPERATING INCOME 1,022 316 2,351 1,549
NONOPERATING EXPENSES 2 314 666 986
NONOPERATING INCOME TAX EXPENSE (CREDIT) 922 (211) 681 (345)
INTEREST CHARGES 9,806 9,058 29,351 29,674
-------- -------- -------- --------
NET INCOME 41,002 51,069 50,974 61,429
PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53 159 159
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 40,949 $ 51,016 $ 50,815 $ 61,270
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $41,002 $51,069 $50,974 $61,429
OTHER COMPREHENSIVE INCOME
Cash Flow Power Hedges (155) - 45 -
------- ------- ------- -------
COMPREHENSIVE INCOME $40,847 $51,069 $51,019 $61,429
======= ======= ======= =======
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 SUBSIDIARY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $107,949 $121,822 $142,994 $137,688
NET INCOME 41,002 51,069 50,974 61,429
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 22,457 13,060 67,368 39,180
Preferred Stock 53 53 159 159
-------- -------- -------- --------
BALANCE AT END OF PERIOD $126,441 $159,778 $126,441 $159,778
======== ======== ======== ========
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 SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,039,184 $1,034,711
Transmission 433,513 427,110
Distribution 990,439 972,806
General 200,679 203,572
Construction Work in Progress 72,710 56,900
---------- ----------
Total Electric Utility Plant 2,736,525 2,695,099
Accumulated Depreciation and Amortization 1,235,343 1,184,443
---------- ----------
NET ELECTRIC UTILITY PLANT 1,501,182 1,510,656
---------- ----------
OTHER PROPERTY AND INVESTMENTS 43,340 41,020
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 15,588 55,215
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 11,808 5,795
Accounts Receivable:
Customers 22,443 31,100
Affiliated Companies 47,556 10,905
Fuel - at LIFO costs 19,511 21,559
Materials and Supplies - at average costs 38,407 36,785
Under-Recovered Fuel Costs 99,845 -
Energy Trading and Derivative Contracts 15,300 162,200
Prepayments and Other 3,286 2,368
---------- ----------
TOTAL CURRENT ASSETS 258,156 270,712
---------- ----------
REGULATORY ASSETS 27,121 35,064
---------- ----------
DEFERRED CHARGES 30,813 5,290
---------- ----------
TOTAL ASSETS $1,876,200 $1,917,957
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 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 180,016 180,016
Accumulated Other Comprehensive Income 45 -
Retained Earnings 126,441 142,994
---------- ----------
Total Common Shareholder's Equity 463,732 480,240
Cumulative Preferred Stock Not Subject
to Mandatory Redemption 5,267 5,267
PSO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of PSO 75,000 75,000
Long-term Debt 245,360 345,129
---------- ----------
TOTAL CAPITALIZATION 789,359 905,636
---------- ----------
OTHER NONCURRENT LIABILITIES 8,360 7,263
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 206,000 106,000
Advances from Affiliates 228,638 123,087
Accounts Payable - General 73,974 72,759
Accounts Payable - Affiliated Companies 75,381 40,857
Customers Deposits 21,268 21,041
Taxes Accrued 29,274 18,150
Over-Recovered Fuel Costs - 8,720
Interest Accrued 10,219 7,298
Energy Trading and Derivative Contracts 17,900 167,658
Other 14,118 12,216
---------- ----------
TOTAL CURRENT LIABILITIES 676,772 577,786
---------- ----------
DEFERRED INCOME TAXES 328,827 296,877
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 32,649 33,992
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 27,306 49,080
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 12,927 47,323
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $1,876,200 $1,917,957
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended September 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 50,974 $ 61,429
Adjustments to Reconcile Net Income to Net Cash From
Operating Activities:
Depreciation and Amortization 64,473 59,458
Deferred Income Taxes 33,841 (25,491)
Deferred Investment Tax Credits (1,343) (1,343)
Deferred Property Taxes (8,092) (8,568)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (27,994) 34,534
Fuel, Materials and Supplies 426 9,644
Other Deferred Credits (201) 1,997
Accounts Payable 35,739 (97,739)
Taxes Accrued 11,124 70,863
Other Property and Investments (2,320) (1,814)
Fuel Recovery (108,565) 67,975
Mark-to-Market Energy Trading Contracts 2,442 (39)
Changes in Other Assets (14,664) (13,460)
Changes in Other Liabilities (17,185) 9,409
--------- --------
Net Cash Flows From Operating Activities 18,655 166,855
--------- --------
INVESTING ACTIVITIES:
Construction Expenditures (51,629) (88,194)
Other - (359)
Proceeds from Sale of Property 963 -
--------- --------
Net Cash Flows Used For Investing Activities (50,666) (88,553)
--------- --------
FINANCING ACTIVITIES:
Retirement of Long-term Debt - (20,000)
Change in Advances From Affiliates (net) 105,551 (22,695)
Dividends Paid on Common Stock (67,368) (39,180)
Dividends Paid on Cumulative Preferred Stock (159) (159)
--------- --------
Net Cash Flows From (Used For) Financing Activities 38,024 (82,034)
--------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 6,013 (3,732)
Cash and Cash Equivalents at Beginning of Period 5,795 11,301
--------- --------
Cash and Cash Equivalents at End of Period $ 11,808 $ 7,569
========= ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $24,853,000 and
$24,351,000 and for income taxes was $2,962,000 and $7,386,000 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
THIRD QUARTER 2002 vs. THIRD 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 to approximately 435,000 retail
customers 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.
Results of Operations
Net Income decreased slightly in the third quarter and decreased $12
million or 14%, for the year-to-date period. The decrease for the year-to-date
period primarily resulted from reduced wholesale margins due to a decline in
demand for electricity resulting from mild weather and a slow economic recovery.
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Electricity Marketing and Trading* $22 10 $(10) (2)
Energy Delivery* 13 13 2 1
Sales to AEP Affiliates (4) (20) (14) (21)
---- ----
Total $ 31 9 $(22) (3)
==== ====
*Reflects the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The increase in revenues for the quarter mainly result from a $31 million
increase due to ICR adjustments (see Note 6).
Operating revenues decreased 3% for the year-to-date period due to
decreased fuel revenues offset in part by the addition of the Dolet Hills mining
operation, increased wholesale revenues and the positive impact of the ICR
adjustments (see Note 6).
Changes in Operating Expenses
Operating expenses increased 11% in the third quarter due to a significant
increase in Electricity Marketing Purchases and Purchases from AEP Affiliates
offset by a decrease in Fuel expense.
Operating expenses decreased 1% for the year-to-date period due to a
decrease in Fuel expense offset by an increase in purchased power.
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Fuel $(12) (9) $(70) (19)
Electricity Marketing Purchases 26 N.M. 27 N.M.
Purchases from AEP Affiliates 8 N.M. 18 171
Other Operation 5 11 19 16
Maintenance 2 9 (2) (3)
Depreciation and Amortization 3 12 3 3
Taxes Other Than Income Taxes - - - 1
Income Taxes (1) (2) (5) (13)
---- ----
Total $ 31 11 $(10) (1)
==== ====
Fuel expense decreased for the quarter and year-to-date due to a
reduction in MWH generated, a decrease in deferred fuel expense in the quarter
and a decrease in the cost of fuel in the year-to-date period.
Purchased power for the quarter and year-to-date increased due to
reduced generation and the impact of ICR adjustments (see Note 6).
The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June
2001 caused Other Operation expense to increase in year-to-date 2002.
Year-to-date and the quarter were impacted by both the addition of Dolet Hills
and the ICR adjustments (see Note 6).
The increase in Depreciation and Amortization expense for the quarter is
due to a favorable excess earnings adjustment in 2001 as required by Texas
Restructuring Legislation. The increase year-to-date is primarily due to the
addition of Dolet Hills in June 2001.
The decrease in Income Taxes for the quarter and year-to-date periods
was due to a decrease in pre-tax income.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $234,435 $212,627 $529,641 $540,088
Energy Delivery 112,084 98,916 265,027 262,943
Sales to AEP Affiliates 15,904 19,898 53,088 67,275
-------- -------- -------- --------
TOTAL OPERATING REVENUES 362,423 331,441 847,756 870,306
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 122,446 134,560 306,536 376,957
Purchased Power:
Electricity Marketing 29,820 4,317 40,290 13,294
AEP Affiliates 10,257 1,878 27,817 10,257
Other Operation 51,005 46,034 137,288 117,926
Maintenance 16,767 15,344 49,547 51,011
Depreciation and Amortization 31,764 28,461 92,437 89,919
Taxes Other Than Income Taxes 15,259 15,208 42,205 41,721
Income Taxes 24,851 25,445 36,925 42,392
-------- -------- -------- --------
TOTAL OPERATING EXPENSES 302,169 271,247 733,045 743,477
-------- -------- -------- --------
OPERATING INCOME 60,254 60,194 114,711 126,829
NONOPERATING INCOME 1,203 1,256 1,618 2,939
NONOPERATING EXPENSES 344 657 1,298 1,977
NONOPERATING INCOME TAX EXPENSE
(CREDIT) 176 (28) 67 58
INTEREST CHARGES 15,143 14,464 42,856 43,723
-------- -------- -------- --------
NET INCOME 45,794 46,357 72,108 84,010
-------- -------- -------- --------
PREFERRED STOCK DIVIDEND REQUIREMENTS 57 57 172 172
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 45,737 $ 46,300 $ 71,936 $ 83,838
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME $45,794 $46,357 $72,108 $84,010
OTHER COMPREHENSIVE INCOME
Cash Flow Power Hedges (180) - 50 -
------- ------- ------- -------
COMPREHENSIVE INCOME $45,614 $46,357 $72,158 $84,010
======= ======= ======= =======
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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $297,187 $294,422 $308,915 $293,989
NET INCOME 45,794 46,357 72,108 84,010
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 18,962 18,554 56,889 55,659
Preferred Stock 57 57 172 172
-------- -------- -------- --------
BALANCE AT END OF PERIOD $323,962 $322,168 $323,962 $322,168
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,491,981 $1,429,356
Transmission 569,688 538,749
Distribution 1,040,372 1,042,523
General 396,435 376,016
Construction Work in Progress 69,590 74,120
---------- ----------
Total Electric Utility Plant 3,568,066 3,460,764
Accumulated Depreciation and Amortization 1,677,142 1,550,618
---------- ----------
NET ELECTRIC UTILITY PLANT 1,890,924 1,910,146
---------- ----------
OTHER PROPERTY AND INVESTMENTS 44,669 43,000
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 17,441 63,372
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 5,704 5,415
Accounts Receivable:
Customers 54,602 44,588
Affiliated Companies 14,402 12,069
Allowance for Uncollectible Accounts (2,143) (89)
Fuel Inventory - at average cost 56,585 52,212
Under-recovered Fuel - 2,501
Materials and Supplies - at average cost 34,750 32,527
Energy Trading and Derivative Contracts 24,561 186,159
Prepayments and Other 19,630 18,716
---------- ----------
TOTAL CURRENT ASSETS 208,091 354,098
---------- ----------
REGULATORY ASSETS 47,777 52,308
---------- ----------
DEFERRED CHARGES 102,841 67,753
---------- ----------
TOTAL ASSETS $2,311,743 $2,490,677
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 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 245,003 245,003
Accumulated Other Comprehensive Income 50 -
Retained Earnings 323,962 308,915
---------- ----------
Total Common Shareowner's Equity 704,675 689,578
Preferred Stock 4,701 4,701
SWEPCO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of SWEPCO 110,000 110,000
Long-term Debt 637,904 494,688
---------- ----------
TOTAL CAPITALIZATION 1,457,280 1,298,967
---------- ----------
OTHER NONCURRENT LIABILITIES 44,450 40,109
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 55,595 150,595
Advances from Affiliates 3,723 117,367
Accounts Payable - General 70,665 71,810
Accounts Payable - Affiliated Companies 45,894 37,469
Customer Deposits 20,448 19,880
Taxes Accrued 93,388 36,522
Interest Accrued 14,489 13,631
Energy Trading and Derivative Contracts 20,027 192,318
Over-recovered Fuel 22,159 -
Other 29,882 26,074
---------- ----------
TOTAL CURRENT LIABILITIES 376,270 665,666
---------- ----------
DEFERRED INCOME TAXES 350,712 369,781
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 48,241 48,714
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 20,326 13,127
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 14,464 54,313
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $2,311,743 $2,490,677
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended September 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 72,108 $ 84,010
Adjustments for Noncash Items:
Depreciation and Amortization 92,437 89,919
Deferred Income Taxes (15,296) (2,534)
Deferred Investment Tax Credits (3,393) (3,321)
Mark-to-Market Energy Trading and Derivative Contracts (4,534) (6,801)
Deferred Property Taxes (8,772) (9,316)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (10,293) (19,657)
Fuel, Materials and Supplies (6,596) 943
Accounts Payable 7,280 (58,817)
Taxes Accrued 56,866 63,653
Fuel Recovery 24,660 16,024
Change in Other Assets (24,717) (4,929)
Change in Other Liabilities 15,889 10,537
--------- ---------
Net Cash Flows From Operating Activities 195,639 159,711
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (73,483) (76,668)
Purchase of Dolet Hills - (85,716)
Other 674 (411)
--------- ---------
Net Cash Flows Used For Investing Activities (72,809) (162,795)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 198,614 -
Retirement of Long-term Debt (150,450) (450)
Change in Advances from Affiliates (net) (113,644) 62,108
Dividends Paid on Common Stock (56,889) (55,659)
Dividends Paid on Cumulative Preferred Stock (172) (172)
--------- ---------
Net Cash Flows From (Used For) Financing Activities (122,541) 5,827
--------- ---------
Net Increase in Cash and Cash Equivalents 289 2,743
Cash and Cash Equivalents at Beginning of Period 5,415 1,907
--------- ---------
Cash and Cash Equivalents at End of Period $ 5,704 $ 4,650
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $34,860,000 and
$38,614,000 and for income taxes was $24,102,000 and $5,524,000 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
THIRD QUARTER 2002 vs. THIRD 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
also sells electric power at wholesale to other utilities, municipalities, rural
electric cooperatives and beginning in 2002 to its affiliated REP in Texas.
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.
On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas. WTU 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 was
required to submit a plan to structurally unbundle its business into a REP, 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 affiliated REP. Pending regulatory approval, WTU will separate its
generation from its transmission and distribution operations. The affiliated REP
is a separate legal entity that is an AEP subsidiary, that is not owned by or
consolidated with WTU.
Since the affiliated REP is the electricity supplier to retail customers
in the ERCOT area, WTU sells its generation to the affiliated REP and other
market participants and provides transmission and distribution services to
retail customers in the WTU service territory. As a result of the formation of
the affiliated REP, effective January 1, 2002, WTU no longer supplies
electricity directly to retail customers. The implementation of affiliated REPs
as suppliers to retail customers has caused a significant shift in WTU's sales
as described below under "Results of Operations."
Results of Operations
Net Income decreased $18 million or 130% for the quarter and $21 million
or 98% year-to-date. The decreases are primarily due to a $22 million impairment
charge, net of tax, related to the inactivation of inefficient gas fired plants
(see Note 10).
Changes in Revenues
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Electricity Marketing and Trading* $(87) (69) $(218) (69)
Energy Delivery* (29) (55) (75) (56)
Sales to AEP Affiliates 87 N.M. 191 N.M.
---- -----
Total $(29) (16) $(102) (22)
==== =====
*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 electricity sales in the ERCOT region as of January 1,
2002, partially offset by the ICR adjustments (see Note 6). Also contributing to
the decrease was a decline in wholesale power prices. In 2002 the wholesale
energy sector has been under pressure from lower commodity prices and fewer
market participants in contrast to last year when performance was stronger 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 decreased due to lower wholesale prices.
Changes in Operating Expenses
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
- -
Fuel $(18) (43) $(67) (45)
Electricity Marketing (9) (18) (13) (19)
Purchases from AEP Affiliates 2 14 (14) (28)
Other Operation 33 127 31 40
Maintenance 1 23 1 5
Depreciation and Amortization (5) (29) (5) (13)
Taxes Other Than Income Taxes (3) (32) (3) (15)
Income Taxes (12) (138) (12) (107)
---- ----
Total $(11) (7) $(82) (19)
==== ====
Fuel expense decreased both for the quarter and year-to-date due to a
decrease in the average unit cost of fuel and decreased generation.
The net decline in Purchased Power expense for both the quarter and
year-to-date was mainly due to reduced prices caused by decreased electricity
demand, partially offset by ICR adjustments (see Note 6).
As a result of WTU's recent ability to purchase electricity at a
significantly lower price than its current cost to generate electricity, WTU
proposed in September 2002 to "inactivate" various, high-cost gas fired
generating facilities. WTU recorded an impairment charge in the third quarter
2002 of approximately $34 million related to these plants which was recorded in
Other Operation expense (see Note 10).
Depreciation and Amortization expense decreased due to the elimination in
2002 of excess earnings expense under Texas Restructuring Legislation.
The quarter and year-to-date decrease in Taxes Other Than Income Taxes is
primarily a result of one-time third quarter 2001 assessments and a decrease in
the gross receipts tax due to deregulation.
The quarter and year-to-date decrease in Income Taxes is primarily a
result of a decrease in pre-tax income resulting from the write-down of various
generating facilities.
Other Changes
Nonoperating Income and Nonoperating Expenses increased significantly
during the quarter and the year-to-date period as a result of increased
non-utility revenue and expenses associated with energy related construction
projects for third parties, offset in part by decreased interest income.
Nonoperating Income Taxes decreased year-to-date due to a decrease in
pre-tax income.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $ 38,249 $124,943 $ 96,064 $314,034
Energy Delivery 23,792 53,182 59,311 134,512
Sales to AEP Affiliates 90,626 3,308 205,370 13,762
--------- -------- -------- --------
Total Operating Revenues 152,667 181,433 360,745 462,308
OPERATING EXPENSES:
Fuel 23,774 41,667 81,596 148,420
Purchased Power:
Electricity Marketing 39,090 47,722 53,015 65,711
AEP Affiliates 12,552 11,022 34,761 48,249
Other Operation 58,270 25,633 107,350 76,735
Maintenance 5,389 4,379 16,795 15,987
Depreciation and Amortization 11,513 16,149 34,154 39,449
Taxes Other Than Income Taxes 5,718 8,460 17,545 20,758
Income Taxes (3,331) 8,656 (855) 11,434
-------- -------- -------- --------
Total Operating Expenses 152,975 163,688 344,361 426,743
OPERATING INCOME (LOSS) (308) 17,745 16,384 35,565
NONOPERATING INCOME 15,446 2,060 20,938 4,358
NONOPERATING EXPENSES 13,639 253 20,898 773
NONOPERATING INCOME TAX EXPENSE
(CREDIT) 599 179 (33) 1,079
INTEREST CHARGES 5,093 5,306 15,983 16,980
-------- -------- -------- --------
NET INCOME (LOSS) (4,193) 14,067 474 21,091
PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26 78 78
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ (4,219) $ 14,041 $ 396 $ 21,013
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
NET INCOME (LOSS) $(4,193) $14,067 $474 $21,091
OTHER COMPREHENSIVE INCOME
Cash Flow Power Hedges (61) - 17 -
------- ------- ---- -------
COMPREHENSIVE INCOME (LOSS) $(4,254) $14,067 $491 $21,091
======= ======= ==== =======
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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $97,087 $115,148 $105,970 $122,588
NET INCOME (LOSS) (4,193) 14,067 474 21,091
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 6,749 7,206 20,247 21,618
Preferred Stock 26 26 78 78
------- -------- -------- --------
BALANCE AT END OF PERIOD $86,119 $121,983 $ 86,119 $121,983
======= ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2002 December 31, 2001
------------------ -----------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 286,179 $ 443,508
Transmission 255,580 250,023
Distribution 442,870 431,969
General 106,665 112,797
Construction Work in Progress 35,757 22,575
---------- ----------
Total Electric Utility Plant 1,127,051 1,260,872
Accumulated Depreciation and Amortization 444,104 546,162
---------- ----------
NET ELECTRIC UTILITY PLANT 682,947 714,710
---------- ----------
OTHER PROPERTY AND INVESTMENTS 26,241 24,933
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 10,029 21,532
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 342 2,454
Accounts Receivable:
Customers 22,087 18,720
Affiliated Companies 46,815 8,656
Allowance for Uncollectible Accounts (358) (196)
Fuel - at average cost 12,067 8,307
Materials and Supplies - at average cost 11,399 11,190
Under-recovered Fuel Costs 23,630 32,791
Energy Trading and Derivative Contracts 14,332 63,252
Prepayments and Other Current Assets 1,725 966
---------- ----------
TOTAL CURRENT ASSETS 132,039 146,140
---------- ----------
REGULATORY ASSETS 19,324 13,733
---------- ----------
DEFERRED CHARGES 15,965 2,446
---------- ----------
TOTAL ASSETS $ 886,545 $ 923,494
========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
September 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 2,351 2,351
Accumulated Other Comprehensive Income 17 -
Retained Earnings 86,119 105,970
-------- --------
Total Common Shareowner's Equity 225,701 245,535
Cumulative Preferred Stock Not Subject to
Mandatory Redemption 2,367 2,367
Long-term Debt 132,483 220,967
-------- --------
TOTAL CAPITALIZATION 360,551 468,869
-------- --------
OTHER NONCURRENT LIABILITIES 7,418 6,296
-------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 35,000 35,000
Advances from Affiliates 195,174 50,448
Accounts Payable - General 34,288 33,782
Accounts Payable - Affiliated Companies 3,870 11,388
Customer Deposits - 4,191
Taxes Accrued 29,356 17,358
Interest Accrued 4,431 1,244
Energy Trading and Derivative Contracts 12,734 65,414
Other 11,364 9,824
-------- --------
TOTAL CURRENT LIABILITIES 326,217 228,649
-------- --------
DEFERRED INCOME TAXES 134,649 145,049
-------- --------
DEFERRED INVESTMENT TAX CREDITS 21,828 22,781
-------- --------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 7,821 18,455
-------- --------
REGULATORY LIABILITIES AND DEFERRED CREDITS 28,061 33,395
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $886,545 $923,494
======== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended September 30,
2002 2001
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 474 $ 21,091
Adjustments for Noncash Items:
Depreciation and Amortization 34,154 39,449
Writedown of Utility Plant Assets 34,215 -
Deferred Income Taxes (14,139) (8,060)
Deferred Investment Tax Credits (953) (953)
Mark-to-Market Energy Trading and Derivative Contracts (2,863) (2,285)
Deferred Property Taxes (3,588) (4,297)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (41,364) 22,277
Fuel, Materials and Supplies (3,969) 1,401
Accounts Payable (7,012) (51,426)
Taxes Accrued 11,998 27,108
Fuel Recovery 9,161 14,245
Change in Other Assets (13,603) (3,469)
Change in Other Liabilities 113 7,388
-------- ---------
Net Cash Flows From Operating Activities 2,624 62,469
-------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (33,338) (28,811)
Other - (127)
--------- ---------
Net Cash Flows Used For Investing Activities (33,338) (28,938)
--------- ---------
FINANCING ACTIVITIES:
Retirement of Long-term Debt (95,799) -
Change in Advances from Affiliates (net) 144,726 (12,448)
Dividends Paid on Common Stock (20,247) (21,618)
Dividends Paid on Cumulative Preferred Stock (78) (78)
--------- ---------
Net Cash Flows From (Used For) Financing Activities 28,602 (34,144)
--------- ---------
Net Decrease in Cash and Cash Equivalents (2,112) (613)
Cash and Cash Equivalents at Beginning of Period 2,454 6,941
--------- ---------
Cash and Cash Equivalents at End of Period $ 342 $ 6,328
========= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $13,061,000 and
$11,761,000 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
SEPTEMBER 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. New Accounting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
Pronouncements
3. Goodwill and Other
Intangible Assets AEP, SWEPCo
4. Acquisitions and
Dispositions AEP
5. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, SWEPCo, WTU
6. Rate Matters AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
7. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
8. Financing and Related
Activities AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, SWEPCo, WTU
9. Commitments and
Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
10. Plant Closings and
Staff Reductions AEP, CPL, 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. NEW ACCOUNTING PRONOUNCEMENTS
During 2002, the EITF discussed Issue No. 02-3, "Recognition and
Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10
and 00-17" (EITF 02-3) and reached consensus on certain issues. EITF
98-10, "Accounting for Contracts Involving Energy Trading and Risk
Management Activities," requires that energy trading contracts be
accounted for at fair value. EITF 02-3 rescinds Issue No. 98-10
effective for any new contracts entered into after October 25, 2002. For
energy trading contracts entered into through October 25, 2002, such
contracts will continue to be accounted for at fair value through
December 31, 2002. Effective January 1, 2003, such contracts are
required to be accounted for at historical cost and we will report this
as a cumulative effect of an accounting change. Our energy contracts
that qualify as derivatives will continue to be accounted for at fair
value under SFAS 133.
EITF 02-3 requires that energy trading contracts and derivatives,
whether settled financially or physically, be reported in the income
statement on a net basis effective January 1, 2003. Previous guidance in
EITF 98-10 permitted non-financial settled energy trading contracts to
be reported either gross or net in the income statement. Prior to the
third quarter of 2002, we recorded and reported upon settlement, sales
under forward trading contracts as revenues and purchases under forward
trading contracts as purchased energy expenses. Effective July 1, 2002,
we reclassified such forward trading revenues and purchases on a net
basis, as permitted by EITF 98-10. The reclassification of such trading
activity to a net basis of reporting resulted in a substantial reduction
in both revenues and purchased energy expense, but did not have any
impact on our financial condition, results of operations or cash flows.
The following table shows the amounts of revenue and Fuel and Purchased
Energy expense that AEP would report if these amounts were presented on
a "gross" basis:
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
---- ---- ---- ----
(in millions) (in millions)
Gross Revenues $21,999 $17,998 $49,844 $45,765
Gross Fuel and Purchased
Energy Expense $19,882 $15,763 $43,709 $39,653
Net Revenues $3,911 $3,757 $10,818 $9,944
Net Fuel and Purchased
Energy Expense $1,794 $1,522 $4,683 $3,832
The FASB issued SFAS 146 which addresses accounting for costs
associated with exit or disposal activities. This statement supersedes
previous accounting guidance, principally EITF No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to
Exit an Activity (including Certain Costs Incurred in a Restructuring)."
Under EITF No. 94-3, a liability for an exit cost was recognized at the
date of an entity's commitment to an exit plan. SFAS 146 requires that
the liability for costs associated with an exit or disposal activity be
recognized when the liability is incurred. SFAS 146 also establishes
that the liability should initially be measured and recorded at fair
value. The timing of recognizing future costs related to exit or
disposal activities, including restructuring, as well as the amounts
recognized may be affected by SFAS 146. We will adopt the provisions of
SFAS 146 for exit or disposal activities initiated after December 31,
2002.
3. GOODWILL AND OTHER INTANGIBLE ASSETS
SFAS 142 was effective for AEP on January 1, 2002. The adoption
of SFAS 142 required 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. The fair values of the UK and
Australia retail electricity and supply operations were estimated using
a combination of market values based on recent market transactions and
cash flow projections. 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 a change in accounting principle.
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 nine
months ended September 30, 2002 by operating segment are:
Energy AEP
Wholesale Delivery Other Consolidated
--------- -------- ----- ------------
(in millions)
Balance January 1, 2002 $340 $37 $ 15 $392
Goodwill acquired 2 - - 2
Goodwill assigned from purchase price
allocation for recent prior period
acquisitions 73 - - 73
Non-transitional impairment loss - - (12) (12)
Foreign currency exchange rate changes 6 - - 6
---- --- ---- ----
Balance September 30, 2002 $421 $37 $ 3 $461
==== === ==== ====
The transitional impairment loss related to SEEBOARD and
CitiPower goodwill, which is reported as a cumulative effect of an
accounting change, is excluded from the above schedule. Under SFAS 144,
the assets of SEEBOARD and CitiPower, including goodwill and acquired
intangible assets no longer subject to amortization, are reported as
Assets of Discontinued Operations on one line in the balance sheet. See
Note 4 related to the sale of SEEBOARD and CitiPower.
In the first quarter of 2002, AEP recognized a goodwill
impairment loss of $12 million ($8 million net of tax) as a result of
management's decision to exit its Gas Power Systems business that was
developing customized generators powered by surplus helicopter engines.
Management elected to exit this business due to technical problems with
the underlying technology and recognized an impairment loss for all
goodwill related to the acquisition of Gas Power Systems.
As required by SFAS 142 the following tables show the
transitional disclosures to adjust reported net income and earnings per
share to exclude amortization expense recognized in prior periods
related to goodwill and intangible assets that are no longer being
amortized.
Three Months Ended
Net Income September 30,
2002 2001
---- ----
(in millions)
Reported Net Income $425 $421
Add back: Goodwill amortization - 9
Add back: Amortization for intangibles with indefinite
lives under SFAS 142 - 2
---- ----
Adjusted Net Income $425 $432
==== ====
Three Months Ended
Earnings Per Share (Basic and Dilutive) September 30,
2002 2001
---- ----
Reported Earnings per Share $1.25 $1.31
Add back: Goodwill amortization - .03
Add back: Amortization for intangibles with indefinite
lives under SFAS 142 - -
----- -----
Adjusted Earnings per Share $1.25 $1.34
===== =====
Nine Months Ended
Net Income September 30,
2002 2001
---- ----
(in millions)
Reported Net Income $318 $919
Add back: Goodwill amortization - 28
Add back: Amortization for intangibles with indefinite
lives under SFAS 142 - 6
---- ----
Adjusted Net Income $318 $953
==== ====
Nine Months Ended
Earnings Per Share (Basic and Dilutive) September 30,
2002 2001
---- ----
Reported Earnings per Share $0.97 $2.85
Add back: Goodwill amortization - 0.09
Add back: Amortization for intangibles with
indefinite lives under SFAS 142 - 0.01
----- -----
Adjusted Earnings per Share $0.97 $2.95
===== =====
Acquired Intangible Assets
Acquired intangible assets subject to amortization are $35
million at September 30, 2002 and $33 million at December 31, 2001 net
of accumulated amortization. The gross carrying amount and accumulated
amortization by major asset class are:
September 30, 2002 December 31, 2001
Gross Carrying Accumulated Gross Carrying Accumulated
Amount Amortization Amount Amortization
-------------- ------------ -------------- ------------
(in millions) (in millions)
Dolet Hills advanced
Royalties $35 $5 $35 $2
Less: Adjustment due
to purchase price
reallocation 6 1 - -
Unpatented Technology 10 - - -
--- -- --- --
Totals $39 $4 $35 $2
=== == === ==
Amortization of intangible assets was $2 million for the nine
months ended September 30, 2002. Estimated aggregate amortization
expense is $4 million for each year 2003 through 2008.
AEP's acquired intangible assets no longer subject to
amortization were comprised of distribution licenses for CitiPower
operating franchises. In accordance with SFAS 144, the assets of
CitiPower, including acquired intangible assets no longer subject to
amortization, are reported as Assets of Discontinued Operations on one
line in the balance sheet. See Note 4 related to the sale of CitiPower.
4. 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
$941 million in net 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 loss of $345 million at June 30, 2002. 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 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 3)
and has been reported as a cumulative effect of a change in accounting
principle retroactive to January 1, 2002. A $46 million reduction of
the net loss was recognized in the third quarter of 2002 to reflect
changes in exchange rates to closing, settlement of working capital
true-up and selling expenses. Proceeds from the sale of SEEBOARD were
used to pay down bank facilities and short-term debt.
The assets and liabilities of SEEBOARD were aggregated on the
balance sheet as Assets of Discontinued Operations and Liabilities of
Discontinued Operations. The major classes of SEEBOARD's assets and
liabilities of discontinued operations are:
December 31, 2001
(in millions)
Assets
Current Assets $ 324
Plant, Property and Equipment, Net 1,283
Goodwill 1,129
Other Assets 96
------
Total Assets of Discontinued Operations $2,832
======
Liabilities
Current Liabilities $ 752
Long-term Debt 701
Deferred Income Taxes 268
Other Liabilities 77
------
Total Liabilities of Discontinued Operations $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 completed the
sale in August 2002 and received net cash of approximately $175 million
and the buyer assumed CitiPower debt of approximately $674 million. AEP
recorded a net charge totaling $125 million as of June 30, 2002. $98
million was recorded in the second quarter of 2002 relating to a loss
on the distribution license intangible asset. The remaining $27 million
of net loss was classified as a transitional goodwill impairment loss
from the adoption of SFAS 142 (see Note 3) and was recorded as a
cumulative effect of a change in accounting principle retroactive to
January 1, 2002.
The loss on the sale of CitiPower increased $8 million to $133
million in the third quarter of 2002 based on actual closing
amounts and exchange rates.
CitiPower's results of operation have been reclassified as
discontinued operations in accordance with SFAS 144. The assets and
liabilities of Citipower have been aggregated on the December 31, 2001,
balance sheet as assets of discontinued operations and liabilities of
discontinued operations. The major classes of CitiPower's assets and
liabilities of discontinued operations are:
December 31, 2001
(in millions)
Assets
Current Assets $ 138
Plant, Property and Equipment, Net 495
Goodwill/Intangibles 466
Other Assets 54
------
Total Assets of Discontinued Operations $1,153
======
Liabilities
Current Liabilities $ 83
Long-term Debt 612
Deferred Income Taxes 86
Other Liabilities 34
----
Total Liabilities of Discontinued Operations $815
====
Total revenues and pretax profit (loss) of the discontinued
operations of SEEBOARD and CitiPower were:
SEEBOARD CitiPower
-------- ---------
(in millions)
Revenues
3 months ended 9/30/01 $ 313 $ 83
3 months ended 9/30/02 - (2)
9 months ended 9/30/01 1,062 251
9 months ended 9/30/02 694 204
Pretax Profit
3 months ended 9/30/01 20 (10)
3 months ended 9/30/02 64 -
9 months ended 9/30/01 100 -
9 months ended 9/30/02 155 (175)
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, subject to
regulatory approval, to transfer two of its Texas retail electric
providers (REPs) to Centrica, a provider of retail energy and other
consumer services. An independent appraiser established the fair market
value for the transaction that was within the range of $133 million to
$153 million specified in the agreement in order for the transaction to
be completed.
If the transaction is approved by the PUCT and others as
agreed by the parties 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. Completion of the
transaction is contingent upon the regulatory approval from the PUCT.
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. Under the
Texas Legislation, REPs are subject to a clawback liability if customer
change does not attain thresholds required by the legislation. AEP is
responsible for a portion of such liability, if any, for the portion of
the period it owned the REPs after January 1, 2002. AEP will also
receive an up-front payment of approximately $39 million from Centrica
associated with the back-office service agreement. If an acceptable
regulatory approval is not obtained by December 31, 2002, either party
has the right to terminate the transaction.
5. INDUSTRY RESTRUCTURING
As discussed in the 2001 Annual Report, customer choice of
electricity supplier has been implemented 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, pricing
standard offer electric generation effective January 1, 2006 at the
market price used by the companies to estimate transition costs 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 delayed in the implementation of their RTO
participation plans. We continue to pursue integration of CSPCo, OPCo
and other AEP East electric operating companies into PJM and anticipate
completing that integration in 2003. Management is unable to predict the
timing of FERC's final approval of RTOs, the timing of an RTO being
operational or the outcome of this proceeding before the PUCO.
In October 2002 the PUCO initiated an investigation of the
financial condition of Ohio's regulated public utilities. The PUCO's
goal is to identify measures available to the PUCO to ensure that the
regulated operations of Ohio's public utilities are not impacted by
adverse financial consequences of parent or affiliate company
unregulated operations and take appropriate corrective action. The
utilities and other interested parties were requested to provide
comments and suggestions by November 12, 2002, with reply comments
November 22, 2002, on the type of information necessary to accomplish
the stated goals, the means to gather the required information from the
public utilities and potential courses of action that the PUCO could
take. Management is unable to predict the outcome of the PUCO's
investigation or its impact on results of operations and business
practices, if any.
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 all
its previous customers under capped rates. 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 or 2003. However, the Virginia restructuring
law allows rates to be adjusted in certain circumstances including
changes in fuel prices. As discussed in Note 6, an APCo requested fuel
factor increase was approved in November 2002 and will be effective on
January 1, 2003. The restructuring law also allows for an adjustment of
non-generation base rates once during the transition period but no
earlier than January 1, 2004. 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 all appropriate regulatory approvals. In
September 2002 the FERC approved our corporate separation plan. SEC
approval remains pending.
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 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 excess cost over market (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.
In order to obtain a market value of generating plant for
purposes of determining stranded costs for the 2004 true-up proceeding,
CPL anticipates filing a plan of divestiture with the PUCT in the fourth
quarter of 2002 seeking approval of a sales process for all of its
generating facilities.
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 Texas Restructuring Legislation provides for an earnings
test each year 1999 through 2001. For CPL, any earnings in excess of the
most recently approved cost of capital in its last rate case must be
applied to reduce stranded costs. Companies without stranded costs,
including SWEPCo and WTU, must pay any excess earnings to customers,
invest them in improvements to transmission or distribution facilities
or invest them to improve air quality at generating facilities. The
Texas Restructuring Legislation required PUCT approval of the annual
earnings test calculation.
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 be used to
reduce stranded costs. 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.
The PUCT staff issued its recommendation for the 2001 earnings
test in September 2002. An estimate of 2001 excess earnings of $8
million for CPL, $2 million for SWEPCo and none for WTU were recorded in
2001. Adjustments to reflect the PUCT staff's estimate of excess
earnings were recorded prior to September 30, 2002. When the PUCT issues
its final order regarding 2001 excess earnings further adjustments may
be necessary. The PUCT staff's report shows excess earnings of $2
million for SWEPCo, $0.7 million for WTU and none for CPL.
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 ended December
31, 2001. As discussed in Note 6 "Rate Matters", WTU filed its final
fuel reconciliation for its ERCOT service territory with the PUCT in
June 2002 and CPL intends to file its final fuel reconciliation by the
end of 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 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 alternative electric
suppliers are registered to compete in I&M's Michigan service territory.
Management has concluded that as of September 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 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 subsequent 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 legislative activity, the
Public Service Commission of West Virginia closed two proceedings
related to electricity restructuring in the summer of 2002.
The two closed West Virginia Commission proceedings related to
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 has reviewed these two proceedings and has
concluded that at this time it is not clear that APCo meets the
requirements to reapply SFAS 71. Management believes definitive action
from the West Virginia Legislature or the Public Service Commission is
required to reapply SFAS 71.
6. RATE MATTERS
ICR Explanation - Affecting AEP, CPL, PSO, SWEPCo and WTU
The AEP West electric operating companies' power is dispatched
real time on an economic basis and is later allocated among the AEP West
electric operating companies using the Interchange Cost Reconstruction
(ICR) system based on dispatch information from internal and external
sources. ICR is designed to allocate the cost of power under the terms
and conditions of the AEP West Operating Agreement.
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 $27.5 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 $293.7 million of eligible fuel and
fuel related expenses serving both ERCOT and SPP retail customers. In
October 2002 the filing was split into two phases. The first phase
examined all components of the filing except for AEP trading activities
and the associated margins that flow back to customers as an offset to
fuel costs. The intervenor groups filed testimony in the first phase
recommending that up to $25 million of WTU's requested retail eligible
fuel recovery be disallowed and hearings were held on October 23, 2002.
WTU disputed the recommendations. On October 21, 2002, the PUCT Staff
and Office of Public Utility Counsel (OPC) filed a joint Motion for
Summary Decision related to the second phase issue and requested that
approximately $18.5 million of WTU's retail eligible fuel recovery be
disallowed without a hearing. On November 8, 2002, the administrative
law judges (ALJs) in the case denied the motion for Summary Judgment.
The PUCT Staff and OPC could appeal the ALJs' decision to the full PUCT.
The intervenors filed testimony on October 29, 2002 in the second phase
recommending that up to $34 million of WTU's requested retail eligible
fuel recovery be disallowed. The intervenors recommended disallowance
includes the amount sought in the October 21 Motion for Summary
Decision. The total recommended retail disallowance is approximately $59
million. Hearings for the second phase will be held on November 13,
2002. The PUCT is not expected to issue a final order in this case until
2003. An adverse ruling from the PUCT could have a material impact on
future results of operations, cash flows and financial condition.
ERCOT Over-scheduling - Affecting AEP, CPL and WTU
In late 2001, the PUCT initiated an investigation of the
impact of scheduling of electric loads and resources by qualified
scheduling entities (QSE) in ERCOT in August 2001. ERCOT began serving
as a central control center for all of ERCOT at the end of July 2001.
QSEs schedule loads and resources for ERCOT market participants
including power generation companies and retail electric providers. In
August 2001 ERCOT incurred substantial costs for managing transmission
in its north zone. The costs incurred by ERCOT to manage congestion are
shared by all ERCOT QSEs. The PUCT's investigation determined that a
substantial amount of the congestion charges were the result of QSEs,
including AEP's QSE, scheduling more resources than required to meet
their actual load requirements in the ERCOT north zone. AEP's QSE
over-scheduled resources due to an error in the allocation of estimated
load requirements between ERCOT congestion zones. Pursuant to the PUCT's
investigation, QSEs, including AEP's QSE, agreed to a settlement that
provides for the refund of payments received for adjusting resource
schedules for congestion. The settlement was approved by the PUCT in
November 2002. The settlement recognizes that the scheduling errors were
associated with the start up of the ERCOT competitive market. Settlement
amounts will be refunded to QSEs in ERCOT. The AEP QSE will pay $3.2
million to ERCOT and expects to receive $1.9 million from ERCOT in
congestion refunds for a net payment of $1.3 million. The ERCOT QSE will
allocate these payments and refunds to WTU and CPL. WTU expects to incur
a net cost of $2.7 million and CPL expects to receive a net refund of
$1.4 million. It is expected that both the WTU payment and CPL refund
will be reflected in the final fuel reconciliations for each company and
as result these amounts are not expected to have any impact on net
income.
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 natural gas and purchased power using NYMEX natural gas prices.
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. On August 26,
2002, the PUCT issued an order approving a 22% increase to the fuel
portion of their "price-to-beat" rates effective immediately for both
CPL REP and WTU REP. The PUCT order approving the 22% increase has been
appealed.
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. In July 2002 FERC approved a revised open access
transmission tariff. Refunds totaling $1.3 million including interest
were issued in August 2002. The allocation of the refunds resulted in
revenue increases of $2.5 million for PSO and $2.8 million for SWEPCo
and revenue reductions of $2.8 million for CPL and $1.2 million for WTU.
Texas Transmission Cost Recovery - Affecting AEP, CPL and WTU
In July 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 received approval to increase their TCRF
by $0.8 million and $0.2 million, respectively. The TCRF increase has
been implemented.
Fuel and Purchased Power Recovery - Affecting AEP, CPL, PSO, SWEPCo
and WTU
PSO has Under-Recovered Fuel Costs of $99.8 million at
September 30, 2002, representing fuel and purchased power costs recorded
but not yet collected from retail customers in Oklahoma and cost to be
allocated among the AEP West electric operating companies. During the
third quarter of 2002, PSO estimated that the under-recovered fuel cost
due to natural gas price increases that were not expected when PSO set
its quarterly factors during the year were approximately $25 million.
The formation of the ERCOT single control zone increased the need for
data estimation and true-up which has resulted in extended true-up
periods associated with allocations performed on estimated data.
During 2002, AEP reallocated purchased power costs among the
four AEP West electric operating companies for the periods prior to
January 1, 2002 (the ICR Adjustments). The effects of the reallocation
on pretax income were insignificant to CPL and PSO and increased pretax
income at SWEPCo and WTU by $2.4 million and $1.9 million, respectively.
As updated or final data become known, AEP is reallocating purchase
power costs among the four AEP West electric operating companies. To
date, completed reallocations of purchased power costs among the AEP
West electric operating companies increased PSO's under-recovered amount
by $44.6 million. The reallocation currently in process is expected to
reduce PSO's under-recovered fuel and purchased power costs and to
increase the costs allocated to the other AEP West electric operating
companies (SWEPCo, CPL and WTU). PSO's next opportunity to request a
change to its fuel factors will be in November 2002, with new rates
beginning December 2002, subject to review and approval by the
Corporation Commission of the State of Oklahoma (OCC). To the extent the
OCC and/or the AEP West Commissions regulating SWEPCo do not permit
recovery of the revised fuel and purchased power costs, there could be
an adverse effect on its results of operations and cash flows.
Furthermore, if the currently pending reallocations result in additional
costs being allocated to CPL and WTU, these additional costs may not be
recoverable since there is no longer a fuel clause for these companies.
As a result, any additional costs that may be reallocated to CPL and WTU
could have an adverse effect on their future results of operations and
cash flows.
Louisiana Compliance Filing - Affecting AEP and SWEPCo
On October 15, 2002, SWEPCo filed with the Louisiana Public
Service Commission (LPSC) detailed financial information typically
utilized in a revenue requirement filing, including a jurisdictional
cost of service. This filing was required as a result of the order by
the LPSC approving the merger between AEP and CSW. The LPSC's merger
order also provides that SWEPCo's base rates are capped at the present
level through mid-year 2005. The filing indicates that SWEPCo's current
rates should not be reduced because SWEPCo's current revenues are below
the level of revenues that SWEPCo should be permitted to recover. This
filing is under review by the LPSC staff. If the LPSC disagrees with our
conclusion, they could order SWEPCo to file a full cost of service
revenue requirement in order to determine whether SWEPCo's capped rates
should be reduced.
FERC Long-term Contracts - Affecting AEP and AEP East and AEP West
electric operating companies
In September 2002 the FERC voted to hold hearings to consider
requests from certain wholesale customers located in western states to
break long-term contracts which they allege are "high-priced". At issue
are long-term contracts entered during the California energy price spike
in 2000 and 2001. The complaints allege that AEP sold power at unjust
and unreasonable prices. The FERC delayed hearings to allow the parties
to hold settlement discussions. Management is unable to predict the
outcome of these proceedings or their impact on results of operations
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. A public hearing was
held on September 23, 2002 related to this filing. On November 8, 2002,
a decision was issued in this proceeding approving an increase of
approximately $24 million.
Environmental Surcharge Filing - Affecting AEP and KPCo
In September 2002 KPCo filed with the KPSC to revise its
environmental surcharge tariff to recover the cost of emissions control
equipment being installed at Big Sandy Plant. See NOx Reductions in Note
9.
The surcharge request, estimated to increase annual revenues
by approximately $21 million, must be approved by the KPSC before its
inclusion in customers' bills. If the KPSC does not approve an increase
in the environmental surcharge, results of operations and cash flows
would be negatively impacted.
7. BUSINESS SEGMENTS
AEP has three business segments: Wholesale,Energy Delivery and
Other. The business activities of each of these segments are as
follows:
Wholesale
oGeneration of electricity for sale to retail and wholesale customers
oGas pipeline and storage services
oMarketing and trading of electricity, gas, coal and other commodities
oCoal mining, bulk commodity barging operations and other energy
supply related businesses
Energy Delivery
oDomestic electricity transmission
oDomestic electricity distribution
Other
oInvestments in foreign power and distribution projects
oTelecommunication services
Segment results of operations for the nine months ended September 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, and income taxes, and the effect of
discontinued operations, extraordinary items and the cumulative effect
of changes in accounting principles. 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. By excluding
discontinued operations, extraordinary items and the cumulative effect
of changes in accounting principles, EBIT gives more focused guidance on
segment operating performance.
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
(in millions)
Nine Months Ended September 30, 2002
Revenues from:
External customers $ 8,020 $2,737 $ 61 $ $ 10,818
-
Transactions with other operating segments 1,643 13 37 (1,693) -
Segment EBIT 939 808 (15) - 1,732
Total assets at September 30, 2002 32,353 12,341 822 - 45,516
Nine Months Ended September 30, 2001
Revenues from:
External customers $ 7,226 $2,599 $ 119 $ - $9,944
Transaction with other operating segments 1,771 14 4 (1,789) -
Segment EBIT 1,226 810 47 - 2,083
Total assets at September 30, 2001 32,632 13,321 8,008 (1,142) 52,819
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.
Nine Months Ended Nine Months Ended
September 30, 2002 September 30, 2001
Segment Segment
Revenues EBIT Total Assets Revenues EBIT Total Assets
Wholesale Segment (in thousands) (in thousands)
APCo $924,196 $175,501 $2,883,704 $ 910,479 $135,287 $3,066,057
CPL 945,495 174,838 3,057,762 981,024 245,947 3,080,135
CSPCo 713,107 227,197 2,025,657 678,139 197,305 2,157,522
I&M 900,334 39,508 3,356,226 926,923 121,130 3,528,300
KPCo 190,571 11,589 629,363 184,338 4,516 638,684
OPCo 1,161,279 303,108 3,159,412 1,194,882 198,107 3,337,773
PSO 322,790 41,779 887,443 606,901 51,063 946,654
SWEPCo 582,729 64,797 1,132,754 607,363 73,034 1,304,534
WTU 301,434 (14,939) 380,328 327,796 12,410 432,338
Segment Segment
Revenues EBIT Total Assets Revenues EBIT Total Assets
Energy Delivery Segment (in thousands) (in thousands)
APCo $444,706 $160,839 $2,274,979 $455,587 $165,744 $2,418,839
CPL 240,066 141,770 2,196,124 449,425 120,376 2,212,194
CSPCo 373,969 71,281 1,139,432 358,984 81,452 1,213,606
I&M 242,416 118,821 1,514,930 241,581 91,305 1,592,600
KPCo 101,137 42,960 609,541 101,367 42,748 618,567
OPCo 447,104 74,866 1,761,791 405,352 78,516 1,861,251
PSO 214,624 68,427 988,757 208,911 75,360 1,054,728
SWEPCo 265,027 87,159 1,178,989 262,943 97,149 1,357,780
WTU 59,311 30,508 506,217 134,512 38,174 575,443
Registrant Subsidiaries
Company Total Revenues EBIT Total Assets Revenues EBIT Total Assets
(in thousands) (in thousands)
APCo $1,368,902 $336,340 $5,158,683 $1,366,066 $301,031 $5,484,896
CPL 1,185,561 316,608 5,253,886 1,430,449 366,323 5,292,329
CSPCo 1,087,076 298,478 3,165,089 1,037,123 278,757 3,371,128
I&M 1,142,750 158,329 4,871,156 1,168,504 212,435 5,120,900
KPCo 291,708 54,549 1,238,904 285,705 47,264 1,257,251
OPCo 1,608,383 377,974 4,921,203 1,600,234 276,623 5,199,024
PSO 537,414 110,206 1,876,200 815,812 126,423 2,001,382
SWEPCo 847,756 151,956 2,311,743 870,306 170,183 2,662,314
WTU 360,745 15,569 886,545 462,308 50,584 1,007,781
In October 2002, we announced our plans to reduce our exposure
to speculative energy trading markets and to downsize our trading and
wholesale marketing operations. It is expected that in the future our
trading and marketing operations will be limited to risk management
around our assets.
8. 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. AEP applies the treasury stock method to
the equity units to calculate diluted earnings per share. This method
of calculation theoretically assumes that the proceeds received as a
result of the forward purchase contract are used to repurchase
outstanding shares.
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 5). The
proceeds were used to reduce CPL's debt and retire 4.5 million shares of
CPL's common stock.
The notes were issued under the following classes:
Principal Interest Scheduled Final Final
Class Amount Rate Payment Date Maturity Date
----- --------- -------- --------------- -------------
(in millions) (%)
A-1 129 3.54 2005 2007
A-2 154 5.01 2008 2010
A-3 107 5.56 2010 2012
A-4 215 5.96 2013 2015
A-5 192 6.25 2016 2017
Other issuances and retirements of long-term debt and
other securities during the first nine 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
AEP Subs. Notes Payable 121 6.225-6.60 2017
Retirements
AEP Senior Unsecured Notes $ 5 6.125 2006
APCo First Mortgage Bonds 40 6.65 2003
APCo First Mortgage Bonds 30 6.85 2003
APCo First Mortgage Bonds 50 7.38 2002
APCo Junior Debentures 75 8-1/4 2026
APCo Junior Debentures 90 8.00 2027
CPL Senior Unsecured Notes 150 Variable 2002
CPL First Mortgage Bonds 73 7-1/4 2004
CPL First Mortgage Bonds 59 7-1/2 2002
CPL First Mortgage Bonds 33 6-7/8 2003
CPL First Mortgage Bonds 56 7-1/8 2008
CPL First Mortgage Bonds 57 7-1/2 2023
CPL First Mortgage Bonds 128 6-5/8 2005
CSPCo Junior Debentures 73 8-3/8 2025
CSPCo Junior Debentures 40 7.92 2027
I&M Installment Purchase Contract 50 Variable 2014
I&M Senior Unsecured Notes 200 Variable 2002
KPCo First Mortgage Bonds 15 7.90 2023
KPCo First Mortgage Bonds 15 6.65 2003
KPCo First Mortgage Bonds 15 6.70 2003
KPCo First Mortgage Bonds 15 6.70 2003
KPCo Notes Payable 25 7.445 2002
OPCo First Mortgage Bonds 5 8.80 2022
OPCo Junior Debentures 85 8.16 2025
OPCo Junior Debentures 50 7.92 2027
SWEPCo Senior Unsecured Notes 150 Variable 2002
WTU First Mortgage Bonds 17 7-3/4 2007
WTU First Mortgage Bonds 22 7 2004
WTU First Mortgage Bonds 16 6-1/8 2004
WTU First Mortgage Bonds 34 6-3/8 2005
Non-Registrant
AEP Subs. Notes Payable 12 Variable 2002-2007
AEP Subs. Revolving Credit Agreement 239 Variable 2003
In addition to the transactions reported in the table above, the
following table lists intercompany issuances and retirements of debt due
to AEP.
Type of Principal Interest
Company Debt Amount Rate Due Date
------- ------- --------- -------- --------
Issuances (in millions) (%)
---------
CSPCo Notes Payable $160 6.501 2006
Retirements
CSPCo Notes Payable $200 Variable 2002
Related Activities
In the third quarter of 2002, all long term debt associated
with SEEBOARD and CitiPower (approximately $1.8 billion) was assumed by the
buyers.
AEP Credit renewed its sale of receivables agreement during the
second quarter of 2002. At September 30, 2002, the sale of receivables
agreement provided commitments of $600 million to purchase receivables
from AEP Credit, of which $528 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 (with a one year term option) 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.
9. COMMITMENTS AND 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, AEPSC, APCo, CSPCo, I&M, and OPCo have been
involved in litigation since 1999 regarding generating plant emissions
under the Clean Air Act. Federal EPA and a number of states alleged
APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities made
modifications to generating units at coal-fired generating plants in
violation of the Clean Air Act. Federal EPA filed complaints against 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 District 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 the 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, PSO, SWEPCo and WTU
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 Commission on Environmental Quality (formerly
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 a variety of emission control technologies to
reduce NOx emissions to comply with the applicable state and Federal NOx
requirements. This includes selective catalytic reduction (SCR)
technology on certain units and non-SCR technologies on a larger number
of units. During 2001 SCR systems commenced operations on OPCo's Gavin
Plant. 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. Non-SCR
technologies have been installed and begun operation on a number of
units across the AEP System and additional units will be equipped with
these technologies.
The AEP NOx compliance plan is a dynamic plan that is continually
reviewed and revised as new information becomes available on the
performance of installed technologies and the cost of planned
technologies. Certain compliance steps may or may not be necessary
dependent on this information. The result is that the plan has a range
of possible outcomes. Our current estimate indicates that AEP's
compliance with the NOx Rule, the Texas Commission on Environmental
Quality rule and the Section 126 Rule could result in required capital
expenditures in the range of $1.3 billion to $2 billion, including
amounts spent through September 30, 2002. The range in the cost estimate
reflects the uncertainty over the need for certain SCR projects.
Estimated compliance cost ranges by registrant subsidiaries are as
follows:
Estimated
Compliance Costs
(in millions)
AEGCo $30 - 198
APCo 445
CPL 5
CSPCo 93
I&M 42 - 210
KPCo 163
OPCo 535 - 864
PSO 1
SWEPCo 40
WTU 5
Since compliance costs cannot be estimated with certainty, the
actual cost to comply could be significantly different than the
estimates depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless any capital and operating costs for
additional pollution control equipment are recovered from customers,
they will have an adverse effect on future results of operations, cash
flows and possibly financial condition.
Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
On October 15, 2002, certain subsidiaries of AEP filed claims
against Enron Corp. and its subsidiaries in the bankruptcy proceeding
filed by the Enron entities which are pending in the U.S. Bankruptcy
Court for the Southern District of New York. At the date of Enron's
bankruptcy AEP had open trading contracts and trading accounts
receivables and payables with Enron. In addition, on June 1, 2001, we
purchased Houston Pipe Line Company (HPL) from Enron. Various HPL
related contingencies and indemnities remained unsettled at the date of
Enron's bankruptcy. The timing of the resolution of the claims by the
Bankruptcy Court is not certain.
In connection with the 2001 acquisition of HPL, we acquired
exclusive rights to use and operate the underground Bammel gas storage
facility pursuant to an agreement with BAM Lease Company, a now-bankrupt
subsidiary of Enron. This exclusive right to use the referenced facility
is for a term of 30 years, with a renewal right for another 20 years and
includes the use of the Bammel storage reservoir and the related
compression, treating and delivery systems. We also entered into an
agreement with BAM Lease Company which grants HPL the right to use
approximately 65 billion cubic feet of cushion gas (or pad gas) required
for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust, which purportedly owned approximately 55 billion cubic feet
of the gas, had entered into a financing arrangement in 1997 with Enron
and a group of banks. These banks purported to have certain rights to
the gas in certain events of default. In connection with AEP's
acquisition of HPL, the banks entered into an agreement granting HPL's
use of the cushion gas and released HPL from liabilities and obligations
under the financing arrangement. HPL was thereafter informed by the
banks of a purported default by Enron under the terms of the referenced
financing arrangement. In July 2002 the banks filed a lawsuit against
HPL seeking a declaratory judgment that they have a valid and
enforceable security interest in this cushion gas which would permit
them to cause the withdrawal of this gas from the storage facility. In
September 2002 HPL filed a general denial and certain counterclaims
against the banks. Management is unable to predict the outcome of this
lawsuit or its impact on results of operations 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 developments in the bankruptcy proceeding or
the lawsuit related to the cushion gas financing agreement our future
results of operations, cash flows and possibly financial condition could
be adversely impacted.
Shareholder Lawsuits - Affecting AEP
In October and November 2002 several lawsuits alleging
securities law violations and seeking class action certification were
filed in Federal District Court, Columbus, Ohio against AEP, certain AEP
executives and in some of the lawsuits against certain investment
banking firms. Some of the lawsuits claim that AEP failed to disclose
that alleged "round trip" trades resulted in an overstatement of
revenues and all of the lawsuits claim that AEP failed to disclose that
AEP traders falsely reported energy prices to trade publications that
publish gas price indices. The plaintiffs seek recovery of an unstated
amount of compensatory damages, attorney fees and costs. The time period
within which others may file to attempt to become lead plaintiff will
end in late December 2002. AEP cannot predict whether any additional
lawsuits will be filed. AEP intends to vigorously defend against these
actions.
Arbitration of Williams Claim - Affecting AEP
In November 2002 AEP filed its demand for arbitration with the
American Arbitration Association to initiate formal arbitration
proceedings in a dispute with the Williams Companies (Williams). The
proceeding results from Williams' failure to provide the monetary
security required for natural gas deliveries by AEP. Consequently, both
parties claimed default and terminated all outstanding natural gas and
electric power trading deals among the various Williams and AEP
affiliates. Williams claimed that AEP owes approximately $130 million in
connection with the termination and liquidation of all trading deals.
AEP believes it has valid claims arising from Williams actions and is
seeking, in part, a determination that either no amount is due or that a
lesser amount is due from AEP to Williams and the extent of any other
damages and legal or equitable relief available. Although management is
unable to predict the outcome of this matter, it is not expected to have
a material impact on results of operations, cash flows or financial
condition.
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".
In August 2002 we received an informal data request from the SEC
asking us to voluntarily provide documents related to "round trip" or
"wash" trades. We have provided the requested information to the SEC.
In September 2002 we received a subpoena from FERC requesting
information about our natural gas transactions and their potential
impact on gas commodity prices in the New York City area. We responded
to the subpoena in October 2002.
On October 9, 2002, AEP dismissed several employees involved in
natural gas marketing and trading after the company determined that they
provided inaccurate price information for use in indexes compiled and
published by trade publications. We have and will continue to provide to
the FERC and the CFTC information relating to price data given to energy
industry publications.
FERC Proposed Security Standards - Affecting AEP System
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 required 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 - Affecting AEP System
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 September 30,
2002 is approximately $88 million and $105 million, respectively. The
cumulative equity share of operating and foreign currency translation
losses through December 31, 2001 was approximately $71 million and $83
million, respectively. 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.
During 2002, Vale and other participants in the electricity
industry in Brazil have experienced reduced cash flows due to the
effects of significant currency devaluation, electricity rationing, and
lower than expected tariffs and demand. There is additional uncertainty
related to the current political environment and the ability to obtain
higher future tariffs from regulators. Vale has principal payments of
$55 million due in November of 2002 and is currently attempting to
refinance or restructure debt and sell assets in order to improve its
cash flows.
The ability of Vale to honor its responsibilities under the put
obligation is dependent on its current and future cash flows and its
ability to refinance or restructure debt and sell assets. Due to Vale's
cash flow difficulties and the current industry and market conditions in
Brazil, we are updating the previous reviews of the collectibility and
value of the put option in order to determine if there is an other than
temporary impairment of our $215 million investment.
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 the
reorganization, divestiture or dissolution of AFN. Management is also
considering a reorganization or divestiture of its other
telecommunications operations in order to optimize the value of such
assets. The review of the telecommunications business strategy, which
was started in the third quarter of 2002, is expected to be completed in
the fourth quarter of 2002. In connection with the completion of this
assessment, management will review its investment in telecommunication
companies for any impairment of value. Management is unable to determine
the extent of any impairment until such evaluation is complete. At
September 30, 2002, AEP's investment in telecommunications companies was
approximately $252 million.
Wind Project - Affecting WTU
WTU is assessing recoverability of certain wind generating assets
due to performance concerns. The net book value of these assets is
approximately $5 million as of September 30, 2002.
Other
AEP and its subsidiary registrants continue to be involved in
certain other matters discussed in the 2001 Annual Report.
10. PLANT CLOSING AND STAFF REDUCTIONS
In September 2002 AEP proposed closing 16 gas-fired power plants
in the ERCOT control area of Texas (8 WTU plants and 8 CPL plants).
ERCOT indicated that it may designate some of those plants as
"reliability must run" (RMR) status. In October ERCOT designated seven
RMR plants (3 WTU plants and 4 CPL plants) and approved AEP's plan to
inactivate nine other plants (5 WTU plants and 4 CPL plants). The
process of moving the plants to inactive status will take up to two
months. Employees of the plants to become inactive (approximately 183)
will be eligible for severance and outplacement services.
RMR plants are required to ensure the reliability of the power
grid, even if electricity from those plants is not required to meet
market needs. ERCOT and AEP negotiated interim contracts for the
remainder of 2002 for the seven RMR plants. It is expected that 2003 RMR
requirements will be announced before the end of 2002.
As a result of the decision to inactivate WTU plants, a
write-down of utility assets of approximately $34 million (pre-tax) was
recorded in Other Operation expense during the third quarter. The
decision to inactivate the CPL plants resulted in a write-down of
utility assets of approximately $100 million which was deferred and
recorded in Regulatory Assets.
Inventory on hand to service the 16 plants is being evaluated for
use at other plants within the AEP System as a part of the closing
process. A write-down, if any, associated with inventory becoming
obsolete as a result of the plant closings will be recorded as
identified during the closing process. Severance benefit arrangements
for employees at these plants are expected to be finalized in the fourth
quarter of 2002.
REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, ACCOUNTING POLICIES AND OTHER MATTERS
This is our combined presentation of management's discussion and
analysis of financial condition, accounting policies 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 September 30, 2002 is presented with their
financial statements earlier in this document.
FINANCIAL CONDITION
Credit Ratings
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 and lowered
First Mortgage Bond ratings of all the registrant subsidiaries to "BBB+" from
"A". AEP's commercial paper programs' short-term ratings of A2 and P2 with
stable outlook have been confirmed by Standard and Poor's and Moody's,
respectively.
In June 2002 Fitch Ratings Service downgraded SWEPCo from A to A- for
senior unsecured notes, but had no further rating actions. Fitch has all
companies on stable outlook and the commercial paper rating is stable at F-2.
The review of the companies' debt position and credit rating is being
completed at our request 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.
At September 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 September 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.
Liquidity
Liquidity, or access to cash, has become a more critical factor in
determining the financial integrity of a company, particularly because of the
volatility of wholesale power markets and the potential limitations that credit
rating downgrades place on a company's ability to raise capital. Management is
committed to preserving an adequate liquidity position and is already addressing
our financial needs for 2003.
As of September 30, 2002, we had an available liquidity position of
$3.3 billion as illustrated in the table below:
Credit Facilities in $ Millions Maturity
- ----------------- ------------- --------
Commercial Paper Backup Lines of Credit $2,500* 5/03
Commercial Paper Backup Lines of Credit 1,000 5/05
Corporate Separation Revolving Credit 1,725 4/03
Other Revolving Credit Facilities 295 10/03
------
Total $5,520
======
Cash
US Liquidity Fund 300**
------
Total Credit Facilities and Cash $5,820
======
Less: Commercial Paper Outstanding 1,967
Corporate Separation Loans 600
------
Total Available Liquidity $3,253
======
* Contains one year term-out provision.
** Unrestricted and excludes $266 million of operational cash on hand.
Our goal is to use cash from operations to fund our capital
expenditures, dividends and working capital. Short-term debt is used as an
interim vehicle to bridge timing differences in the needs for cash and to fund
debt maturities until permanent financing is arranged.
Short-term debt comes from a commercial paper program at the parent
company. Proceeds are loaned to the subsidiaries through intercompany notes. We
also operate a money pool and sell accounts receivable to provide liquidity for
our domestic electric subsidiaries. The commercial paper program is backed by
$3.5 billion in bank facilities of which $1 billion matures in May 2005. The
remaining $2.5 billion matures in May 2003 and has a one-year term-out provision
at the company's option. At September 30, 2002 approximately $1.97 billion of
commercial paper was outstanding. A significant portion of the commercial paper
balance is related to funding of debt maturities of the Ohio and Texas
subsidiaries pending a permanent financing program as part of corporate
separation. The Ohio and Texas subsidiaries plan to begin the permanent
financing program in the near future and the commercial paper balance should
therefore decrease substantially as early as in the fourth quarter of this year.
AEP also has a $1.725 billion bank facility maturing in April 2003 that
is available for debt refinancing in anticipation of corporate separation. At
September 30, 2002, $600 million was outstanding under that facility. We
anticipate refinancing that amount as part of the permanent financing as
discussed above. If the permanent financing for corporate separation is
completed as planned we do not anticipate needing this facility beyond its
maturity in April 2003.
We also have revolving credit facilities in place for 300 million Euros
to support the wholesale business in Europe. As of September 30, 2002, none of
these amounts were drawn. As noted in the table above, AEP also maintains a $300
million cash liquidity reserve fund to support its trading and marketing
operations in the U.S.
In total, we had approximately $5.8 billion in liquidity sources of
which $3.3 billion were unused and available at September 30, 2002.
During the first nine months of 2002 cash flow from operations was $755
million, including $702 million from Net Income from Continuing Operations and
$973 million from depreciation, amortization, deferred taxes, and deferred
investment tax credits offset by additional working capital requirements. These
additional working capital requirements reflect the one time impact of the
discontinuance of the sale of accounts receivable for Texas companies and
billing delays related to the transition to customer choice in Texas, higher
margin requirements for gas trading, seasonal fuel inventory growth, and other
miscellaneous items. Capital expenditures including acquisitions were $1,147
million. Major construction expenditures included amounts for emission control
technology on several coal-fired generating units (see discussion in Note 9).
Dividends on common stock were $590 million. Cash from operations, proceeds from
the sale of SEEBOARD and CitiPower, and the issuance of common stock, common
equity units, 15-year notes for a wind generation project and transition funding
bonds provided funds to reduce debt, fund construction and pay dividends.
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 a portion of available cash. Interim financing
arrangements are being negotiated for the UK generating plants to replace a
portion of the existing (pound)403 million bridge financing that is currently in
place. Completion of this interim financing is anticipated prior to year-end.
During 2003 long-term financing will be sought to replace the interim financing.
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 were $406 million and $89 million, respectively. In order to pay
for a portion of these retired bonds, as well as previously retired bonds, we
borrowed $600 million under the $1,725 million corporate separation revolving
credit facility.
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
our consolidated balance sheet.
Total consolidated plant and property additions including capital leases
for the nine months ended September 30, 2002 were $1,148 million. The following
table shows the plant and property additions by certain registrant subsidiaries:
Company Amount
------- ------
(in millions)
APCo $175
CPL 99
I&M 95
OPCo 224
SWEPCo 73
Completed, 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 and 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 net cash of approximately $941
million which was used to reduce debt. The sale resulted in a loss of $299
million (see Note 4).
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 2002 we completed the sale of CitiPower, our energy delivery and
retail supply businesses in Australia. AEP received approximately $175 million
in net cash which we used to reduce debt. The sale resulted in a $133 million
loss (see Note 4).
AEP provides telecommunications services to businesses and
telecommunication companies through a broadband fiber optic network. AEP
conducts its telecommunication 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 the reorganization,
divestiture or dissolution of AFN. Management is also considering a
reorganization or divestiture of its other telecommunications operations in
order to optimize the value of such assets. The review of the telecommunications
business strategy, which was started in the third quarter of 2002, is expected
to be completed in the fourth quarter of 2002. In connection with the completion
of this assessment, management will review its investment in telecommunication
companies for any impairment of value. Management is unable to determine the
extent of any impairment until such evaluation is complete. At
September 30, 2002, AEP's investment in telecommunications companies was
approximately $252 million.
In October 2002 the City Commission of Elk City, Oklahoma voted to hold
a referendum seeking voter approval of a $20.4 million acquisition of PSO's
distribution assets within the city limits. The vote is expected to occur in
December 2002. If the referendum passes, Elk City, per the terms of their
franchise with PSO, will buy the assets at their fair market value, estimated to
be approximately $20 million. Estimated annual revenues from the customers
served in Elk City is $7.5 million. Management is unable to predict the result
of this vote.
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. In Texas, we intend to transfer the generation
assets from the integrated electric operating companies (CPL and WTU) to
unregulated generation companies. In Ohio, we intend to transfer transmission
and distribution assets from the integrated companies to two new wires companies
leaving CSPCo and OPCo as generating companies. We proposed amendments to the
power pooling agreements to remove the four Ohio and Texas generating 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. Negotiated settlement
agreements with the state regulatory commissions and other major intervenors
were filed with the FERC in December 2001. In September 2002 the FERC
conditionally approved our corporate separation plan including the settlement
agreements. Terms in the settlement agreements, which would be effective upon
implementation of corporation separation, include extension of the base rate
freeze and fuel clause cap for Indiana through 2007 and extension of certain
power supply contracts. In addition, SEC approval of our corporate separation
plan is required for its implementation. The Arkansas Public Service Commission
intervened at the SEC which may extend the length of time needed for the SEC's
review. In order to execute this separation, we may be required to retire
various debt securities and will need 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 the SPP.
In December 2001 the FERC rejected the Alliance RTO's filing.
Subsequently, in May 2002 AEP announced an agreement with the PJM
Interconnection to pursue terms for certain subsidiaries to participate in PJM.
Final agreements are currently being 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. In September 2002 AEP notified the FERC of a memorandum
of understanding which would permit western transmission assets in SPP to
participate in MISO. 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.
ACCOUNTING POLICIES
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - The consolidated financial statements of AEP and the
financial statements of electric operating subsidiary companies with cost-based
rate-regulated operations (APCo, CPL, CSPCo, OPCo, SWEPCo, WTU, I&M, KPCo, PSO),
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 to
be recovered in the future) and regulatory liabilities (deferred 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 and by matching income with its passage to
customers through regulated revenues in the same accounting period. Regulatory
liabilities are also recorded to provide currently for refunds to customers that
have not yet been made.
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 - Revenues are recognized
on the accrual or settlement basis for normal retail and wholesale 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 purchased electricity is received and when expenses
are incurred.
Domestic Gas Pipeline and Storage Activities - Revenues are recognized 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.
Substantially all of the forward gas purchase and sale contracts,
excluding wellhead purchases of natural gas, swaps and options for the domestic
pipeline operations, qualify as derivative financial instruments as defined by
SFAS 133. Accordingly, net gains and losses resulting from revaluation of these
contacts to fair value during the period are recognized currently in the results
of operations, appropriately discounted and net of applicable credit and
liquidity reserves.
Energy Marketing and Trading Activities - AEP engages in non-regulated wholesale
electricity and natural gas marketing and trading transactions (trading
activities). A portion of the revenues and costs associated with AEP's wholesale
electricity trading activities is allocated to CPL, SWEPCo, PSO and WTU and to
members of the AEP Power Pool (APCo, CSPCo, I&M, KPCo, OPCo). AEP's 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 traded futures and options and over-the-counter
options and swaps; however CPL, SWEPCo, PSO and WTU are only allocated a portion
of the forward transactions.
AEP recognizes 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 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. Unrealized mark-to-market gains and losses are included in the
Balance Sheet as "Energy Trading and Derivative Contracts." Our cost-based
rate-regulated electric public utility companies (I&M, KPCo, PSO, and a portion
of SWEPCo) defer, as regulatory liabilities (unrealized gains) or regulatory
assets (unrealized losses), changes in the fair value of physical forward sale
and purchase contracts in AEP's traditional marketing area. AEP's traditional
marketing area is up to two transmission systems from the AEP service territory.
For contracts which are outside of AEP's traditional marketing area, the change
in fair value is included in nonoperating income on a net basis.
The majority of trading activities represent physical forward contracts
that are typically settled by entering into offsetting contracts. An example of
our energy trading activities is when, in January, we enter into a forward sales
contract to deliver energy 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 for a sales contract and the realized cost
for a purchase contract are included on a net basis in revenues with the prior
change in unrealized fair value reversed out of revenues.
For I&M, PSO, KPCo and a portion of SWEPCo, 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 for
sales and the cost of purchased energy are included in revenues on a net basis.
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 contracts with
delivery points outside of AEP's traditional marketing area only the difference
between the accumulated unrealized net gains or losses recorded in prior periods
and the cash proceeds is recognized in the income statement as nonoperating
income. 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.
For APCo, CSPCo and OPCo, depending on whether the delivery point for
the electricity is in AEP's traditional marketing area or not determines where
the contract is reported in the income statement. Physical forward trading sale
and purchase contracts with delivery points in AEP's traditional marketing area
are included in revenues on a net basis. Prior to settlement, changes in the
fair value of physical forward sale and purchase contracts in AEP's traditional
marketing area are also included in revenues on a net basis. Physical forward
sale and purchase contracts for delivery outside of AEP's traditional marketing
area are included in nonoperating income 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 for AEP, APCo, OPCo, CPL, WTU, CSPCo
and a portion of SWEPCo, assume that later in January or sometime in February
through July we enter into an offsetting forward contract to buy energy 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. 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. 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.
For AEP, the trading of energy 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. APCo, CSPCo, OPCo, I&M and KPCo also
have financial transactions, but record the unrealized gains and losses, as well
as the net proceeds upon settlement, in nonoperating income.
The fair values of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based primarily on valuation models that 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 aforementioned valuation models. This is particularly true for long-term
contracts.
AEP applies MTM accounting to 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.
Volatility in energy commodities markets affects the fair values of all
of our open trading and derivative contracts exposing us 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 used to manage our exposure to market
and other risks from trading activities.
New Accounting Pronouncements
During 2002, the EITF discussed Issue No. 02-3, "Recognition and
Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and
00-17" (EITF 02-3) and reached consensus on certain issues. EITF 98-10,
"Accounting for Contracts Involving Energy Trading and Risk Management
Activities," requires that energy trading contracts be accounted for at fair
value. EITF 02-3 rescinds Issue No. 98-10 effective for any new contracts
entered into after October 25, 2002. For energy trading contracts entered into
through October 25, 2002, such contracts will continue to be accounted for at
fair value through December 31, 2002. Effective January 1, 2003, such contracts
are required to be accounted for at historical cost and we will report this as a
cumulative effect of an accounting change. Our energy contracts that qualify as
derivatives will continue to be accounted for at fair value under SFAS 133.
EITF 02-3 requires that energy trading contracts and derivatives,
whether settled financially or physically, be reported in the income statement
on a net basis effective January 1, 2003. Previous guidance in EITF 98-10
permitted non-financial settled energy trading contracts to be reported either
gross or net in the income statement. Prior to the third quarter of 2002, we
recorded and reported upon settlement, sales under forward trading contracts as
revenues and purchases under forward trading contracts as purchased energy
expenses. Effective July 1, 2002, we reclassified such forward trading revenues
and purchases on a net basis, as permitted by EITF 98-10. The reclassification
of such trading activity to a net basis of reporting resulted in a substantial
reduction in both revenues and purchased energy expense, but did not have any
impact on our financial condition, results of operations or cash flows.
The FASB issued SFAS 146 which addresses accounting for costs
associated with exit or disposal activities. This statement supersedes previous
accounting guidance, principally EITF No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a
liability for an exit cost was recognized at the date of an entity's commitment
to an exit plan. SFAS 146 requires that the liability for costs associated with
an exit or disposal activity be recognized when the liability is incurred. SFAS
146 also establishes that the liability should initially be measured and
recorded at fair value. The timing of recognizing future costs related to exit
or disposal activities, including restructuring, as well as the amounts
recognized may be affected by SFAS 146. We will adopt the provisions of SFAS 146
for exit or disposal activities initiated after December 31, 2002.
OTHER MATTERS
Industry Restructuring
As discussed in Note 5 and the 2001 Annual Report, restructuring and
customer choice began in four of the eleven state retail jurisdictions in which
the AEP electric utility companies operate. Restructuring legislation provides
for a transition from cost-based regulation of bundled electric service to
customer choice and market pricing for the supply of electricity. Customer
choice of electricity supplier began on January 1, 2001 for Ohio customers and
on January 1, 2002, for Michigan, Texas and Virginia customers. In 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, pricing standard offer
electric generation effective January 1, 2006 at the market price used by the
companies to estimate transition costs 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 delayed in the implementation their RTO participation plans. We
continue to pursue integration of CSPCo, OPCo and other AEP East electric
operating companies into PJM and anticipate completing that integration in 2003.
Management is unable to predict the timing of FERC's final approval of RTO
participation.
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 be used to reduce
stranded costs. 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 final fuel
reconciliation with the PUCT to reconcile their fuel costs through the period
ended 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 to the risk of fuel market price increases and
could adversely affect future results of operations.
In order to obtain a market value of generating plant for purposes of
determining stranded costs for the 2004 true-up proceeding, CPL anticipates
filing a plan of divestiture with the PUCT in the fourth quarter of 2002 seeking
approval of a sales process for all of its generating facilities.
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 for
recovery through distribution rates pending the 2004 true-up proceeding's
determination of stranded cost recovery. 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 plant costs and other restructuring
related costs, it could have a material adverse effect on results of operations,
cash flows and possibly financial condition.
Reduction of Trading Exposure
In October 2002, we announced our plans to reduce our exposure to
speculative energy trading markets and to downsize our trading and wholesale
marketing operations. It is expected that in the future our trading and
marketing operations will be limited to risk management around our assets.
Litigation
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M,
and OPCo
As discussed in the 2001 Annual Report, AEPSC, APCo, CSPCo, I&M, and
OPCo have been involved in litigation since 1999 regarding generating plant
emissions under the Clean Air Act. Federal EPA and a number of states alleged
APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities made modifications to
generating units at coal-fired generating plants in violation of the Clean Air
Act. Federal EPA filed complaints against 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 District 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 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 Commission on Environmental Quality (formerly 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 a variety of emission control technologies to reduce
NOx emissions to comply with the applicable state and Federal NOx requirements.
This includes selective catalytic reduction (SCR) technology on certain units
and non-SCR technologies on a larger number of units. During 2001 SCR systems
commenced operations on OPCo's Gavin Plant. 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.
Non-SCR technologies have been installed and begun operation on a number of
units across the AEP System and additional units will be equipped with these
technologies.
The AEP NOx compliance plan is a dynamic plan that is continually
reviewed and revised as new information becomes available on the performance of
installed technologies and the cost of planned technologies. Certain compliance
steps may or may not be necessary dependent on this information. The result is
that the plan has a range of possible outcomes. Our current estimate indicates
that AEP's compliance with the NOx Rule, the Texas Commission on Environmental
Quality rule and the Section 126 Rule could result in required capital
expenditures in the range of $1.3 billion to $2 billion, including amounts spent
through September 30, 2002. The range in the cost estimate reflects the
uncertainty over the need for certain SCR projects.
The following table shows the estimated range of compliance costs for
certain of AEP's registrant subsidiaries.
Company Amount
------- ------
(in millions)
APCo $445
CPL 5
I&M 42-210
OPCo 535-864
SWEPCo 40
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
On October 15, 2002, certain subsidiaries of AEP filed claims against
Enron Corp. and its subsidiaries in the bankruptcy proceeding filed by the Enron
entities which are pending in the U.S. Bankruptcy Court for the Southern
District of New York. At the date of Enron's bankruptcy AEP had open trading
contracts and trading accounts receivables and payables with Enron. In addition,
on May 31, 2001, we purchased Houston Pipe Line Company (HPL) from Enron.
Various HPL related contingencies and indemnities remained unsettled at the date
of Enron's bankruptcy. The timing of the resolution of the claims by the
Bankruptcy Court is not certain.
In connection with the 2001 acquisition of HPL, we acquired
exclusive rights to use and operate the underground Bammel gas storage facility
pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of
Enron. This exclusive right to use the referenced facility is for a term of 30
years, with a renewal right for another 20 years and includes the use of the
Bammel storage reservoir and the related compression, treating and delivery
systems. We also entered into an agreement with BAM Lease Company which grants
the right to use approximately 65 billion cubic feet of cushion gas (or pad gas)
required for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust, which purportedly owned approximately 55 billion cubic feet of the
gas, had entered into a financing arrangement in 1997 with Enron and a group of
banks. These banks purported to have certain rights to the gas in certain events
of default. In connection with AEP's acquisition of HPL, the banks entered into
an agreement granting HPL's use of the cushion gas and released HPL from
liabilities and obligations under the financing arrangement. HPL was thereafter
informed by the banks of a purported default under the terms of the referenced
financing arrangement. In July 2002 the banks filed a lawsuit against HPL
seeking a declaratory judgment that they have a valid and enforceable security
interest in this cushion gas which would permit them to cause the withdrawal of
this gas from the storage facility. In September 2002 HPL filed a general denial
and certain counterclaims against the banks. Management is unable to predict the
outcome of this lawsuit or its impact on results of operations 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
developments in the bankruptcy proceeding or the lawsuit related to the cushion
gas financing agreement our future results of operations, cash flows and
possibly financial condition could be adversely impacted.
Shareholder Lawsuits - Affecting AEP
In October and November 2002 several lawsuits alleging securities law
violations and seeking class action certification were filed in Federal District
Court, Columbus, Ohio against AEP, certain AEP executives and in some of the
lawsuits against certain investment banking firms. Some of the lawsuits claim
that AEP failed to disclose that alleged "round trip" trades resulted in an
overstatement of revenues and all of the lawsuits claim that AEP failed to
disclose that AEP traders falsely reported energy prices to trade publications
that publish gas price indices. The plaintiffs seek recovery of an unstated
amount of compensatory damages, attorney fees and costs. The time period within
which others may file to attempt to become lead plaintiff will end in late
December 2002. AEP cannot predict whether any additional lawsuits will be filed.
AEP intends to vigorously defend against these actions.
Spent Nuclear Fuel Disposal Fund Litigation - Affecting AEP, CPL and I&M
As discussed in the 2001 Annual Report, I&M and STPNOC, on behalf of
STP's joint owners, joined a lawsuit against DOE, filed in November 2000 by
unaffiliated utilities, related to DOE's nuclear waste fund cost recovery
settlement with PECO Energy Company (now Exelon Generation Company, LLC). The
settlement adjusted the fees Exelon was required to pay to DOE for disposal of
SNF. The fee adjustment allowed Exelon to skip payments to the DOE to make up
for Exelon's damages from DOE's breach of its contract obligation to dispose of
SNF from commercial nuclear power plants. The companies believed the settlement
was unlawful as it would have forced other utilities (rather than DOE) to
compensate Exelon for the damages it had incurred from DOE's breach of contract.
In September 2002 the U.S. Court of Appeals for the Eleventh Circuit found that
DOE acted improperly by adopting the fee adjustment provision of this
settlement, that the fee adjustment provisions of the settlement harmed other
utilities who pay into the fund and violated the federal nuclear waste
management laws and that the fee adjustment provisions of the settlement were
null and void.
Arbitration of Williams Claim - Affecting AEP
In October 2002 AEP filed its demand for arbitration with the
American Arbitration Association to initiate formal arbitration proceedings in a
dispute with the Williams Companies (Williams). The proceeding results from
Williams' failure to provide the monetary security required for natural gas
deliveries by AEP. Consequently, both parties claimed default and terminated all
outstanding natural gas and electric power trading deals among the various
Williams and AEP affiliates. Williams claimed that AEP owes approximately $130
million in connection with the termination and liquidation of all trading deals.
AEP believes it has valid claims arising from Williams actions and is seeking,
in part, a determination that either no amount is due or that a lesser amount is
due from AEP to Williams and the extent of any other damages and legal or
equitable relief available. Although management is unable to predict the outcome
of this matter, it is not expected to have a material impact on results of
operations, cash flows or financial condition.
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".
In August 2002 we received an informal data request from the SEC asking
us to voluntarily provide documents related to "round trip" or "wash" trades. We
have provided the requested information to the SEC.
In September 2002 we received a subpoena from FERC requesting
information about our natural gas transactions and their potential impact on gas
commodity prices in the New York City area. We responded to the subpoena in
October 2002.
On October 9, 2002, AEP dismissed several employees involved in natural
gas marketing and trading after the company determined that they provided
inaccurate price information for use in indexes compiled and published by trade
publications. We have and will continue to provide to the FERC and the CFTC
information relating to price data given to energy industry publications.
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 September 30,
2002 is approximately $88 million and $105 million, respectively. The cumulative
equity share of operating and foreign currency translation losses through
December 31, 2001 was approximately $71 million and $83 million, respectively.
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.
During 2002, Vale and other participants in the electricity industry in
Brazil have experienced reduced cash flows due to the effects of significant
currency devaluation, electricity rationing, and lower than expected tariffs and
demand. There is additional uncertainty related to the current political
environment and the ability to
obtain higher future tariffs from regulators. Vale has principal payments of $55
million due in November of 2002 and is currently attempting to refinance or
restructure debt and sell assets in order to improve its cash flows.
The ability of Vale to honor its responsibilities under the put
obligation is dependent on its current and future cash flows and its ability to
refinance or restructure debt and sell assets. Due to Vale's cash flow
difficulties and the current industry and market conditions in Brazil, we are
updating the previous reviews of the collectibility and value of the put option
in order to determine if there is an other than temporary impairment of our $215
million investment.
FERC Proposed Security Standards - Affecting AEP System
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 - Affecting AEP System
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.
Pension Plan Funded Status
AEP sponsors two qualified pension plans and two nonqualified pension
plans in the U.S. Substantially all employees are covered by one or both of the
pension plans. AEP no longer sponsors foreign pension plans for SEEBOARD in the
U.K. and CitiPower in Australia since the divestiture of these investments in
2002 (see Note 4).
During the first three quarters of 2002, the market value of the assets
in AEP's qualified pension plans declined by approximately $690 million, or 20
percent, to $2.75 billion due to plan benefit payments and the poor performance
of the financial markets. The actuarially estimated accumulated benefit
obligation (ABO) for the year ended December 31, 2002 is approximately $3.5
billion. There have been no contributions to these plans in 2002 to date. AEP is
in full compliance with all regulations governing such plans including all
Employee Retirement Income Security Act of 1974 (ERISA) laws. Management is
currently evaluating the appropriateness of making contributions to the plans to
improve their funded status.
If the ABO of these plans continues to exceed the market value of plan
assets at December 31, 2002, AEP would be required to record an unfavorable
adjustment to the accumulated other comprehensive income (AOCI) component of
shareholders' equity (net of tax) and a pension liability in its consolidated
balance sheet. AEP cannot currently estimate either the magnitude of this
potential adjustment or any additional required contributions to the plans due
to uncertainty about the factors impacting these computations, including the
performance of plan investments over the remainder of the year and the impact of
any changes in actuarial assumptions used to determine the ABO. However, AEP
estimates that if using the current market value of pension plan assets and
updated actuarial assumptions, including the effect of the current discount
assumption, an unfavorable after-tax adjustment of approximately $600 million
would be required to the AOCI component of shareholders' equity at December 31,
2002.
Continued poor performance of the financial markets could significantly
increase the future cost of pension and other post-employment benefits and
increase funding requirements beyond 2002.
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 Executive
Committee and administered by a Chief Risk Officer. The Risk Executive Committee
establishes risk limits, approves risk policies, assigns responsibilities
regarding the oversight and management of risk and monitors risk levels. This
committee receives daily, weekly, and monthly reports regarding compliance with
policies, limits and procedures. The committee meets monthly and consists of the
Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.
We use a risk measurement model which calculates Value at Risk (VaR) to
measure our commodity price risk in the trading portfolio. 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 September 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:
Nine Months Ended Year Ended
September 30, December 31,
2002 2001
---- ----
High Average Low High Average Low
(in millions) (in millions)
AEP $21 $12 $7 $28 $14 $5
APCo 2 1 1 4 1 -
CPL - - - 3 1 -
CSPCo 2 1 - 2 1 -
I&M 2 1 - 3 1 -
KPCo 1 - - 1 - -
OPCo 2 1 - 3 1 -
PSO - - - 2 1 -
SWEPCo - - - 3 1 -
WTU - - - 1 1 -
We also utilize a VaR model to measure interest rate market risk
exposure. The interest rate VaR model is based on a Monte Carlo simulation with
a 95% confidence level and a one year holding period. The volatilities and
correlations were based on three years of weekly prices. The risk of potential
loss in fair value attributable to AEP's exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $481 million at
September 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), frozen by settlement agreements in Michigan and West Virginia and capped
in Indiana. To the extent the fuel supply of the generating units in these
states is not under fixed price long-term contracts AEP is subject to market
price risk. AEP continues to be protected against market price changes by active
fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP
area of Texas.
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,
weather, freight, euro dollars, 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 those limits unless specifically approved by the Risk Executive
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 our
financial condition at September 30, 2002. At September 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
Counterparty and Swap
Credit Quality: Contracts Options Total
September 30, 2002
(in millions)
AAA/Exchanges $ 3 $ - $ 3
AA 156 6 162
A 329 8 337
BBB 759 163 922
Below Investment
Grade 97 21 118
------ ---- -----
Total $1,344 $198 $1,542
====== ==== ======
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 September 30, 2002 and December
31, 2001 were $317 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 third quarter of 2002 resulted in an
unrealized increase in revenues of $139 million and unrealized increase in
revenues of $202 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 liquid portions of these curves are validated on a regular basis by the
mid-office through the use of independent broker quotes and market data.
Illiquid portions of the curves are validated through a review of the underlying
market assumptions and variables for consistency and reasonableness. The end of
the month liquidity reserve is based on the difference in price between the
price curve and the bid price if we have a long position and the price curve 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, specifically I&M, KPCo, PSO and a portion of SWEPCo, is deferred
as regulatory assets (losses) or liabilities (gains) 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).
Nine Months Ended
September 30,
2002
(in millions)
Revenues (including mark-to-market adjustment) $10,818
Fuel and Purchased Energy Expense 4,683
-------
Net Revenues $ 6,135
=======
Mark-to-Market Revenues on Open Trading Positions $202
====
Percentage of Net Revenues Represented by
Mark-to-Market on Open Trading Positions 3%
==
The following tables analyze the changes in fair values of trading
assets and liabilities. The first table "Net Fair Value of Energy Trading and
Derivative Contracts" 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 and Derivative
Contracts" 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 September 30, 2002
of $228 million. Contracts realized/settled during the period include both sales
and purchase contracts. The third table "Energy Trading and Derivative 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 and Derivative Contracts
September 30, December 31,
2002 2001
---- ----
(in millions) (in millions)
Energy Trading and Derivative Contracts:
Current Asset $ 7,897 $ 8,536
Long-term Asset 3,027 2,368
Current Liability (8,008) (8,288)
Long-term Liability (2,693) (2,176)
-------
Net Fair Value of Energy Trading and Derivative Contracts 223 440
Less non-trading related derivatives (5) -
Assets held for sale (CitiPower) - 8
------- -------
Net Fair Value of Energy Trading and Derivative Contracts $ 228 $ 448
======= =======
The above net fair value of energy trading and derivative contracts
includes $202 million at September 30, 2002, in unrealized mark-to-market gains
that are recognized in the income statement at September 30, 2002.
AEP Consolidated Energy Trading and Derivative Contracts
(in millions)
Total
Net Fair Value of Energy Trading and Derivative Contracts
at December 31, 2001 $ 448
Gain from Contracts realized/settled during period (141) (a)
Fair Value of new open contracts when entered into during the period 67 (b)
Net option premiums received (227) (c)
Change In fair value due to Methodology Changes 1 (d)
Changes in fair market value of energy trading contracts allocated to
regulated jurisdiction 3 (e)
Changes in market value of contracts 77 (f)
-----
Net Fair Value of Energy Trading and Derivative Contracts
at September 30, 2002 $ 228
=====
(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.
(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) Net Option Premiums Paid/(Received) reflects the net option premiums
paid/(received) as they relate to unexercised and unexpired option
contracts that were entered into in 2002.
(d) 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.
(e) "Change in Market Value of Contracts allocated to Regulated
Jurisdictions" relates to the net gains of those contracts that are
not reflected in the income statement. These net gains are recorded as
regulatory liabilities for those subsidiaries that operate in
regulated jurisdictions.
(f) "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.
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 (12,628) 9,213 (9,847)
Change in Fair Value Due To
Methodology Changes 350 42 228
Changes in fair market value of energy
trading contracts allocated to
regulated jurisdictions - - -
Fair Value of new open Contracts
when entered into during period 10,865 1,919 7,039
Net option premium payments 30 - 20
Changes in market value of Contracts 29,092 (6,560) 23,594
-------- ------- --------
Net Fair Value of Energy Trading
Contracts at September 30, 2002 $103,410 $ 8,471 $ 69,483
======== ======= ========
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 2,595 2,041 (13,051)
Change in Fair Value Due To
Methodology Changes 247 90 311
Changes in fair market value of energy
trading contracts allocated to
Regulated jurisdiction 4,742 6,202 -
Fair Value of new open Contracts
when entered into during period 2,774 1,013 18,443
Net option premium payments 21 8 26
Changes in market value of Contracts 4,078 4,591 28,715
-------- ------- --------
Net Fair Value of Energy Trading
Contracts at September 30, 2002 $ 75,802 $26,674 $ 99,890
======== ======= ========
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 6,477 8,058 2,858
Change in Fair Value Due To
Methodology Changes 32 36 12
Changes in fair market value of energy
trading contracts allocated to
Regulated jurisdiction (5,438) (2,533) 626
Fair Value of new open Contracts
when entered into during period - 428 1,627
Net option premium payments - - -
Changes in market value of Contracts - (4,968) (2,259)
------- ------- -------
Net Fair Value of Energy Trading
Contracts at September 30, 2002 $ 3,505 $ 3,921 $ 3,779
======= ======= =======
Energy Trading Contract Maturities
Fair Value of Contracts at September 30, 2002
Maturities
(in millions)
Total Fair
AEP Consolidated Less than 4-5 years In Excess Value
--------- -----
Source of Fair Value 1 year 1-3 years Of 5 years
- -------------------- ------ --------- ----------
Prices actively quoted (a) $(155) $ 55 $ - $ - $(100)
Prices provided by other external
Sources (b) 145 131 3 - 279
Prices based on models and other
Valuation methods (c) (100) 62 52 35 49
----- ---- --- --- -----
Total $(110) $248 $55 $35 $ 228
===== ==== === === =====
Energy Trading Contract Maturities
Fair Value of Contracts at September 30, 2002
Maturities
(in thousands)
Total Fair
Less than 4-5 years In Excess Value
--------- -----
Source of Fair Value 1 year 1-3 years Of 5 years
- -------------------- ------ --------- ----------
APCo
Prices provided by other
External Sources (b) $19,111 $33,878 $ 740 $ - $ 53,729
Prices based on models and other
Valuation methods (c) 9,829 17,697 12,279 9,876 49,681
------- ------- ------- ------ --------
Total $28,940 $51,575 $13,019 $9,876 $103,410
======= ======= ======= ====== ========
CPL
Prices provided by other
External Sources (b) $ 2,940 $1,797 $ 40 $ - $ 4,777
Prices based on models and other
Valuation methods (c) 1,517 967 671 539 3,694
------- ------ ------ ------ --------
Total $ 4,457 $2,764 $ 711 $ 539 $ 8,471
======= ====== ====== ====== ========
CSPCo
Prices provided by other
External Sources (b) $12,814 $22,774 $ 498 $ - $ 36,086
Prices based on models and other
Valuation methods (c) 6,608 11,897 8,254 6,638 33,397
------- ------- ------- ------ --------
Total $19,422 $34,671 $ 8,752 $6,638 $ 69,483
======= ======= ======= ====== ========
KPCo
Prices provided by other
External Sources (b) $ 4,919 $ 8,743 $ 191 $ - $ 13,853
Prices based on models and other
Valuation methods (c) 2,536 4,564 3,171 2,550 12,821
------- ------- ------- ------- --------
Total $ 7,455 $13,307 $ 3,362 $ 2,550 $ 26,674
======= ======= ======= ======= ========
I&M
Prices provided by other
External Sources (b) $18,607 $21,264 $ 532 $ - $40,403
Prices based on models and other
Valuation methods (c) 6,764 12,699 8,832 7,104 35,399
------- ------- ------ ------ -------
Total $25,371 $33,963 $9,364 $7,104 $75,802
======= ======= ====== ====== =======
OPCo
Prices provided by other
External Sources (b) $23,606 $32,032 $ 660 $ - $56,298
Prices based on models and other
Valuation methods (c) 8,110 15,724 10,951 8,807 43,592
------- ------- ------- ------ -------
Total $31,716 $47,756 $11,611 $8,807 $99,890
======= ======= ======= ====== =======
PSO
Prices provided by other
External Sources (b) $ 572 $1,181 $ 27 $- $ 1,780
Prices based on models and other
Valuation methods (c) 295 635 440 355 1,725
------- ------ ---- ---- -------
Total $ 867 $1,816 $467 $355 $ 3,505
======= ====== ==== ==== =======
SWEPCo
Prices provided by other
External Sources (b) $ 640 $1,321 $ 30 $ - $ 1,991
Prices based on models and other
Valuation methods (c) 330 710 493 397 1,930
------- ------ ---- ---- -------
Total $ 970 $2,031 $523 $397 $ 3,921
======= ====== ==== ==== =======
WTU
Prices provided by other
External Sources (b) $ 1,042 $ 984 $ 22 $ - $2,048
Prices based on models and other
Valuation methods (c) 538 531 367 295 1,731
------- ------ ---- ---- ------
Total $ 1,580 $1,515 $389 $295 $3,779
======= ====== ==== ==== ======
(a) "Prices Actively Quoted" represents the Company's exchange traded
futures positions.
(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.
CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures. Our chief
executive officer and our chief financial officer, after
evaluating the effectiveness of the Company's "disclosure
controls and procedures" (as defined in the Securities Exchange
Act of 1934 Rules 13a-14(c) and 15d-14(c)) as of a date (the
"Evaluation Date") within 90 days before the filing date of this
quarterly report, have concluded that as of the Evaluation Date,
our disclosure controls and procedures were adequate and
designed to ensure that material information relating to us and
our consolidated subsidiaries would be made known to them by
others within those entities.
(b) Changes in internal controls. There were no significant changes
in our internal controls or to our knowledge, in other factors
that could significantly affect our disclosure controls and
procedures subsequent to the Evaluation Date.
PART II. OTHER INFORMATION
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 and page O-3 of the Quarterly Report on Form 10-Q
for the quarter ended June 30, 2002 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. On September 19, 2002, the D.C.
Circuit Court denied Federal EPA's petition seeking rehearing as well as
petitions filed by several other parties.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
Exhibit 12 - Computation of Consolidated Ratio of Earnings to
Fixed Charges.
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 August 13, 2002 Item 7. Financial Statements and
Exhibits
Item 9. Regulation FD Disclosure
AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
No reports on Form 8-K were filed during the quarter ended September 30,
2002.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signatures for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/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: November 13, 2002
CERTIFICATIONS
I, E. Linn Draper, Jr., certify that:
1. I have reviewed this quarterly report on Form 10-Q of:
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
West Texas Utilities Company;
2. Based on my knowledge, this quarterly report does not
contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements
made, in light of the circumstances under which such
statements were made, not misleading with respect to the
period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report,
fairly present in all material respects the financial
condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior
to the filing date of this quarterly report (the
"Evaluation Date"); and
c) presented in this quarterly report our conclusions about
the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant role
in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes
in internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Dated: November 13, 2002 By: /s/ E. Linn Draper, Jr.
------------------------
E. Linn Draper, Jr.
Chief Executive Officer
I, Susan Tomasky, certify that:
1. I have reviewed this quarterly report on Form 10-Q of:
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
West Texas Utilities Company;
2. Based on my knowledge, this quarterly report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made,
not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report,
fairly present in all material respects the financial
condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Dated: November 13, 2002 By: /s/ Susan Tomasky
------------------------
Susan Tomasky
Chief Financial Officer